-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QLKyyu7N/vl7L6GJvmionD7421UsCwr4NbnPDBDjT0OX/pU1KC80+xSPLwAEcOuR BrCXMjkkRwTqNxLWGAZEyg== 0000950129-04-001612.txt : 20040329 0000950129-04-001612.hdr.sgml : 20040329 20040329142902 ACCESSION NUMBER: 0000950129-04-001612 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: GENESIS ENERGY LP CENTRAL INDEX KEY: 0001022321 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM BULK STATIONS & TERMINALS [5171] IRS NUMBER: 760513049 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-12295 FILM NUMBER: 04695662 BUSINESS ADDRESS: STREET 1: 500 DALLAS SUITE 2500 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138602500 MAIL ADDRESS: STREET 1: 500 DALLAS SUITE 2500 CITY: HOUSTON STATE: TX ZIP: 77002 10-K 1 h14014e10vk.txt GENESIS ENERGY, L.P. 12/31/2003 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2003 OR | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-12295 GENESIS ENERGY, L.P. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 76-0513049 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 860-2500 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ------------------- Common Units American Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No | | Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). | | The aggregate market value of the Common Units held by non-affiliates of the Registrant on June 30, 2003 (the last business day of Registrant's most recently completed second fiscal quarter), was approximately $52,612,500 based on $6.10 per unit, the closing price of the Common Units as reported on the American Stock Exchange on such date. At March 1, 2004, 9,313,811 Common Units were outstanding. ================================================================================ GENESIS ENERGY, L.P. 2003 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
Page ---- PART I Items 1. Business and Properties............................................................... 3 and 2 Item 3. Legal Proceedings..................................................................... 11 Item 4. Submission of Matters to a Vote of Security Holders................................... 13 PART II Item 5. Market for Registrant's Common Units and Related Unitholder Matters................... 13 Item 6. Selected Financial and Operating Data................................................. 14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 15 Item 7A. Quantitative and Qualitative Disclosures about Market Risks........................... 41 Item 8. Financial Statements and Supplementary Data........................................... 41 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 41 Item 9A. Controls and Procedures............................................................... 41 PART III Item 10. Directors and Executive Officers of Our General Partner............................... 42 Item 11. Executive Compensation................................................................ 44 Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 46 Item 13. Certain Relationships and Related Transactions........................................ 47 Item 14. Principal Accountants Fees and Services............................................... 48 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 48
2 FORWARD-LOOKING INFORMATION The statements in this Annual Report on Form 10-K that are not historical information may be "forward looking statements" within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These statements include, but are not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," or "intend" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. These risks and uncertainties include general economic conditions, market and business conditions, opportunities that may be presented and pursued by us or the lack of such opportunities, competitive actions by other companies in our industries, changes in laws and regulations, access to capital, and other factors. Therefore, all the forward-looking statements made in this document are qualified in their entirety by these cautionary statements, and no assurance can be made that our goals will be achieved or that expectations regarding future developments will prove to be correct. Please read "Other Matters- Risk Factors Related to Our Business" discussed in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. PART I ITEMS 1AND 2. BUSINESS AND PROPERTIES WEBSITE ACCESS TO REPORTS We make available free of charge on our internet website (www.genesiscrudeoil.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 available as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. GENERAL Genesis Energy, L.P., a Delaware limited partnership, was formed in December 1996. We conduct our operations through our affiliated limited partnership, Genesis Crude Oil, L.P. and its subsidiary partnerships (collectively, the "Partnership" or "Genesis"). We are engaged in three operations - crude oil gathering and marketing, crude oil pipeline transportation and carbon dioxide (CO2) marketing. We are an independent gatherer and marketer of crude oil. Our operations are concentrated in Texas, Louisiana, Alabama, Florida, and Mississippi. Our gathering and marketing margins are generated by buying crude oil at competitive prices, efficiently transporting or exchanging the crude oil and marketing the crude oil to customers at favorable prices. We utilize our trucking fleet of 49 leased tractor-trailers and our gathering lines to transport crude oil. We also transport purchased crude oil on trucks, barges and pipelines owned and operated by third parties. Our operations include transportation of crude oil at regulated published tariffs on our three common carrier pipeline systems. These systems are the Texas System, the Jay System extending between Florida and Alabama, and the Mississippi System extending between Mississippi and Louisiana. The Jay and Mississippi pipeline systems have numerous points where the crude oil owned by the shipper can be injected into the pipeline for delivery to or transfer to connecting pipelines. The Texas pipeline system receives all of its volume from connections to other carriers. Genesis earns a tariff for the transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point. In November 2003, we acquired assets enabling us to start a wholesale CO2 operation. We acquired a volumetric production payment from Denbury Resources Inc. that will provide us with 167.5 billion cubic feet (Bcf) 3 of CO2. We also acquired from Denbury three of their long-term industrial supply contracts for CO2. We will ship the CO2 from the source to the customers on a pipeline owned by Denbury and will sell the CO2 to the customers. These sales contracts extend through 2015. Genesis Energy, Inc. (the "General Partner"), a Delaware corporation, serves as the sole general partner of Genesis Energy, L.P., Genesis Crude Oil, L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. The General Partner is owned by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc. Denbury acquired the General Partner from Salomon Smith Barney Holdings Inc. and Salomon Brothers Holding Company Inc. in May 2002. DESCRIPTION OF SEGMENTS AND RELATED ASSETS Crude Oil Gathering and Marketing In our gathering and marketing business, we are principally engaged in the purchase and aggregation of crude oil for resale at various points along the crude oil distribution chain, which extends from the wellhead to aggregation at terminal facilities and refineries. (the "Distribution Chain"). We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transport the crude oil along the Distribution Chain for sale to or exchange with customers. Our margins from our gathering and marketing operations are generated by the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation and the cost of supplying credit. We generally enter into an exchange transaction only when the cost of the exchange is less than the alternative costs that we would otherwise incur in transporting or storing the crude oil. In addition, we may exchange one grade of crude oil for another to maximize margins or meet contractual delivery requirements. Segment margin from our crude oil gathering and marketing operations varies from period to period, depending, to a significant extent, upon changes in the supply of and demand for crude oil and the resulting changes in U.S. crude oil inventory levels. Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. An increase in the market price of crude oil does not impact us to the extent many people expect. When market prices for crude oil increase, we must pay more for crude oil, but we normally are able to sell it for more. To the extent we have crude oil inventories; we can be impacted by market price changes. We also make bulk purchases of crude oil at pipeline and terminal facilities. When opportunities arise to increase margin or to acquire a grade of crude oil that more nearly matches the specifications for crude oil we are obligated to deliver, we may exchange crude oil with third parties through exchange or buy/sell agreements. Both bulk purchases and buy/sell agreements were significantly reduced in 2002 compared to prior years. During 2003, our bulk and exchange transactions averaged 12,000 barrels per day, down from 246,319 barrels per day in the fourth quarter of 2001. The reduction is attributable primarily to credit requirements for these transactions as discussed below. We provide crude oil gathering services through our fleet of 49 leased tractor-trailers. The trucking fleet generally hauls the crude oil to one of the approximately 60 pipeline injection stations owned or leased by us. We may sell the crude oil as it exits our injection station and enters the pipeline, or we may ship the crude oil on the pipeline to a point further along the Distribution Chain. Producer Services Crude oil purchasers who buy from producers compete on the basis of competitive prices and quality of services. Through our team of crude oil purchasing representatives, we maintain relationships with more than 400 producers. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. High-quality field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline 4 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 calculating and paying production taxes on behalf of interest owners. In order to compete effectively, we must make prompt and correct payment of crude oil production proceeds on a monthly basis, together with the correct payment of all severance and production taxes associated with such proceeds. In 2003, we distributed payments to approximately 17,000 interest owners. Credit Our credit standing is an important consideration for parties with whom we do business. Some counterparties, in connection with our crude oil purchases or exchanges, require us to furnish guarantees or letters of credit. When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. Since typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is an important consideration in our business. We believe that our sales are made to creditworthy entities or entities with adequate credit support. We have not experienced any nonpayment or nonperformance by our customers. Over the last three years there have been an unusual number of business failures and very large restatements by small as well as large companies in the energy industry. Because the energy industry is very credit intensive, these failures and restatements have focused attention on the credit risks of companies in the energy industry by credit rating agencies, producers and counterparties. This focus on credit has affected requests for credit from producers. While we have seen some increase in requests for credit support from producers, we have been relatively successful in obtaining open credit from most producers. When credit support has been required, we have generally been successful in adjusting the price we pay to purchase the crude oil to reflect our cost of providing letters of credit. Credit review and analysis are also integral to our leasehold purchases. Payment for all or substantially all of the monthly leasehold production is sometimes made to the operator of the lease, who is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, we determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend us in the event any third party should bring a protest, action or complaint in connection with the distribution of production proceeds by the operator. Competition In the crude oil gathering and marketing business, there is intense competition for leasehold purchases of crude oil. The number and location of our pipeline systems and trucking facilities give us access to domestic crude oil production throughout our area of operations. We purchase leasehold barrels from more than 400 producers. We have considerable flexibility in marketing the volumes of crude oil that we purchase, without dependence on any single customer or transportation or storage facility. Our largest competitors in the purchase of leasehold crude oil production are Plains Marketing, L.P., Link Energy Partners, L.P., Shell Trading Company, GulfMark Energy, Inc. and TEPPCO Partners, L.P. Additionally, we compete with many regional or local gatherers who may have significant market share in the areas in which they operate. Competitive factors include price, personal relationships, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems. As part of the sale of our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P., we agreed not to compete in a 40 county area for five years from the effective date of the transaction of October 31, 2003. See additional information on this sale below. Crude Oil Pipeline Transportation Through the pipeline systems we own and operate our pipeline subsidiaries transport crude oil for our gathering and marketing operations and other shippers pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") or the Texas Railroad Commission. Accordingly, we offer transportation services to any shipper of crude oil, provided that the products tendered for transportation satisfy the conditions and 5 specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the particular point where the crude oil was injected into the pipeline and the delivery point. We also can earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses from whatever source, we deduct volumetric pipeline loss allowances and crude quality deductions. Such allowances and deductions are offset by measurement gains and losses. When the allowances and deductions exceed measurement losses, the net pipeline loss allowance volumes are earned and recognized as income and inventory available for sale valued at the market price for the crude oil. Until the volumes are sold, they are held as inventory at the lower of cost or market value. When the volumes are sold, any difference between the carrying amount and the sale price is recognized as additional pipeline revenue. The margins from our pipeline operations are generated by the difference between the revenues from regulated published tariffs, pipeline loss allowance revenues and the fixed and variable costs of operating and maintaining our pipelines. We own and operate three common carrier crude oil pipeline systems. The pipelines and related gathering systems consist of the 135-mile Texas system, the 103-mile Jay System, and the 266-mile Mississippi System. In 2003 we sold portions of our Texas system to TEPPCO Crude Pipeline, L.P. and to Blackhawk Pipeline, L.P., an affiliate of MultiFuels, Inc. The segments we sold to TEPPCO included Bryan to Hearne, Conroe to Satsuma, Hillje to West Columbia and Withers to West Columbia. TEPPCO also acquired our crude oil gathering and marketing operations in the 40 county area surrounding the pipeline. The segments we sold to Blackhawk had been idle since 2002. These segments include Neches to Satsuma, Raccoon Bend to Satsuma and a short portion of the segment from Satsuma to Cullen Junction. We abandoned in place segments that had been idled in 2002, primarily between Satsuma and Cullen Junction. The segments we continue to operate extend from West Columbia to Webster, Cullen Junction to Webster, Webster to Texas City and Webster to Houston. These segments include approximately 135 miles of pipe. We entered into a joint tariff with TEPPCO to receive oil from their system at West Columbia and Cullen Junction. We also continue to receive barrels from a connection with Seminole Pipeline Company at Webster. The joint tariff arrangement with TEPPCO ends in September 2004 when we will idle the West Columbia to Webster segment and the Cullen Junction to Webster segment. We will idle these segments to avoid the costs of testing and possible repairs required under pipeline integrity management regulations. See Regulation - Safety Regulations below. We will evaluate alternatives at that time, including converting the segments to natural gas service. We own approximately 500,000 barrels of storage capacity associated with the Texas pipeline system that is temporarily being used in conjunction with our transitional arrangement with TEPPCO. Once TEPPCO integrates the assets they acquired from us into their operations, we will idle all of this storage capacity. Additionally, we lease approximately 200,000 barrels of storage capacity for the Texas System in Webster. The Mississippi system extends from Soso, Mississippi to Liberty, Mississippi and then from Liberty, Mississippi to near Baton Rouge, Louisiana. We own 200,000 barrels of storage capacity on our Mississippi System, with the tankage located at different places along the system. The segment of the Mississippi system from Liberty to Baton Rouge has been temporarily idled since February 2002. In the second quarter of 2004, we will remove the oil from this segment of the pipeline and consider alternatives for its use, including product or natural gas service. The Jay system begins near oil fields in southeastern Alabama and the panhandle of Florida and extends to a point near Mobile, Alabama. The Jay system has 230,000 barrels of storage capacity, primarily at Jay station. Credit Under the tariffs we have filed with the FERC and the Texas Railroad Commission, shippers are required to pay the tariff invoices we send to them within ten days of receipt of the invoices. If they fail to do so, we can charge interest and suspend service to that shipper. Because shippers do not want any disruption in shipments, they generally pay the invoices promptly. Additionally, the larger shippers on our systems are large oil companies. Under the joint tariff with TEPPCO for the Texas system, TEPPCO invoices and collects the tariff from the shipper and remits to us our share of the joint tariff. 6 The only shipper on our Mississippi system as of December 31, 2003 is Genesis Crude Oil, L.P. Genesis buys production from producers, primarily Denbury, and ships it on the pipeline for sale at Liberty to third parties. Competition Our most significant competitors in our pipeline operations are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where the Mississippi and Texas Systems deliver crude oil. The Jay System operates in an area not currently served by pipeline competitors. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to production, refineries and connecting pipelines. We believe that high capital costs, tariff regulation and the cost of acquiring rights-of-way make it unlikely that other competing crude oil pipeline systems, comparable in size and scope to our pipelines, will be built in the same geographic areas in the near future, provided that our pipelines continue to have available capacity to satisfy demands of shippers and that our tariffs remain competitive. CO2 Marketing In November 2003, we entered the wholesale CO2 marketing business. We acquired a volumetric production payment from Denbury consisting of 167.5 Bcf of CO2. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. We also acquired from Denbury three long-term CO2 agreements with industrial customers to supply CO2 through 2015. Denbury transports the CO2 to the customer, charging us a fee. We then sell the CO2 to the customers who treat the CO2 and sell it to end users for use it for beverage carbonation and food chilling and freezing. The margins from the CO2 operations are generated by the difference between the sales price of the CO2 to the industrial customers and the costs of the transportation provided by Denbury. Credit The three customers we have contracts with for CO2 sales are large companies with good credit ratings. We do not expect to experience any credit related issues with these customers, however we do monitor their credit standings on an ongoing basis. Competition Naturally-occurring CO2, like that from the Jackson Dome area, occurs infrequently, and only in limited areas east of the Mississippi River, including the fields controlled by Denbury. This natural CO2 requires less processing and treatment in order to be of a quality to be used in food than does CO2 that is a by-product of fertilizer production. Our industrial CO2 customers have facilities that are connected to Denbury's CO2 pipeline to make delivery easy and efficient. CO2 does have other uses, such as tertiary recovery in oil fields, should the food industries uses decline. Our contracts have take-or-pay provisions requiring minimum volumes each year for each customer that must be paid for even if the CO2 is not taken. EMPLOYEES To carry out various purchasing, gathering, transporting and marketing activities, the General Partner employed, at December 31, 2003, approximately 200 employees, including management, truck drivers and other operating personnel, division order analysts, accountants, tax specialists, contract administrators, schedulers, marketing and credit specialists and employees involved in our pipeline operations. None of the employees are represented by labor unions, and we believe that relationships with our employees are good. REGULATION Sarbanes-Oxley Act of 2002 In July 2002, the Sarbanes-Oxley Act of 2002 was signed into law to protect investors by improving the accuracy and reliability of corporate disclosures made pursuant to securities laws. The Securities and Exchange Commission has issued rules to adopt and implement the Sarbanes-Oxley Act. These rules include certifications by our Chief Executive Officer and Chief Financial Officer in our quarterly and annual filings with the SEC; disclosures regarding controls and procedures, disclosures regarding critical accounting estimates and policies and 7 requirements to make filings with the SEC available on our website. Additional rules include disclosures regarding audit committee financial experts and charters, disclosure of our Code of Ethics for the CEO and senior financial officers, disclosures regarding contractual obligations and off-balance sheet arrangements and transactions, and requirements for filing earnings press releases with the SEC. Additionally, we will be required to include in our Form 10-K for 2004 an internal control report that contains management's assertions regarding the effectiveness of procedures over financial reporting and a report from our auditors attesting to that certification. Our deadlines for filing quarterly and annual filings with the SEC will also be shortened under the regulations. Pipeline Tariff Regulation The interstate common carrier pipeline operations of the Jay and Mississippi systems are subject to rate regulation by FERC under the Interstate Commerce Act ("ICA"). FERC regulations require that oil pipeline rates be posted publicly and that the rates be "just and reasonable" and not unduly discriminatory. Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were "grandfathered", limiting the challenges that could be made to existing tariff rates. Increases from grandfathered rates of interstate oil pipelines are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the year to year change in an index. Under the regulations, we are able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. FERC allows for rate changes under three methods--a cost-of-service methodology, competitive market showings ("Market-Based Rates"), or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). The pipeline tariff rates on our Mississippi and Jay Systems are either rates that were grandfathered and have been changed under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party. Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Texas Railroad Commission. The applicable Texas statutes require that pipeline rates be non-discriminatory and provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. Most of the volume on our Texas system is now shipped under a joint tariff with TEPPCO. Approximately 10% of the volume shipped is pursuant to a tariff we issued. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained. Environmental Regulations We are subject to federal and state laws and regulations relating to the protection of the environment. At the federal level such laws include the Clean Air Act; the Clean Water Act; the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the National Environmental Policy Act. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties or in the imposition of injunctive relief. Although compliance with such laws has not had a significant effect on our business, such compliance in the future could prove to be costly, and there can be no assurance that we will not incur such costs in material amounts. The Clean Air Act regulates, among other things, the emission of volatile organic compounds in order to minimize the creation of ozone. Such emissions may occur from the handling or storage of crude oil. The required levels of emission control are established in state air quality control implementation plans. Both federal and state laws impose substantial penalties for violation of these applicable requirements. We believe that we are in substantial compliance with applicable clean air requirements. The Clean Water Act controls the discharge of oil and derivatives into certain surface waters. The Clean Water Act provides penalties for any discharges of crude oil in harmful quantities and imposes liability for the costs of removing an oil spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of crude oil in surface waters or into the ground. Federal and state permits for water discharges may be required. The Oil Pollution Act of 1990 ("OPA"), as amended by the Coast Guard Authorization Act of 1996, requires operators of offshore facilities and certain onshore facilities near or 8 crossing waterways to provide financial assurance in the amount of $35 million to cover potential environmental cleanup and restoration costs. This amount is subject to upward regulatory adjustment. We believe that we are in substantial compliance with the Clean Water Act and OPA. We have developed an Integrated Contingency Plan (ICP) to satisfy components of the OPA, as amended in the Clean Water Act. The ICP also satisfies regulations of the federal Department of Transportation, the federal Occupational Safety and Health Act ("OSHA") and state regulations. This plan meets regulatory requirements as to notification, procedures, response actions, response teams, response resources and spill impact considerations in the event of an oil spill. The Resource Conservation and Recovery Act regulates, among other things, the generation, transportation, treatment, storage and disposal of hazardous wastes. Transportation of petroleum, petroleum derivatives or other commodities may invoke the requirements of the federal statute, or state counterparts, which impose substantial penalties for violation of applicable standards. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. Such persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the ordinary course of our operations, substances may be generated or handled which fall within the definition of "hazardous substances." Although we have applied operating and disposal practices that were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the property owned or leased by us or under locations where such wastes have been taken for disposal. Further, we may own or operate properties that in the past were operated by third parties whose operations were not under our control. Those properties and any wastes that may have been disposed of or released on them may be subject to CERCLA, RCRA and analogous state laws, and we potentially could be required to remediate such properties. Under the National Environmental Policy Act ("NEPA"), a federal agency, in conjunction with a permit holder, may be required to prepare an environmental assessment or a detailed environmental impact study before issuing a permit for a pipeline extension or addition that would significantly affect the quality of the environment. Should an environmental impact study or assessment be required for any proposed pipeline extensions or additions, the effect of NEPA may be to delay or prevent construction or to alter the proposed location, design or method of construction. We are subject to similar state and local environmental laws and regulations that may also address additional environmental considerations of particular concern to a state. On December 20, 1999, we had a spill of crude oil from our Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek and river nearby. The spill was cleaned up, with ongoing monitoring and reduced clean-up activity expected to continue for an undetermined period of time. The oil spill is covered by insurance and the financial impact to us for the cost of the clean-up has not been material. During 2002, we reached agreement in principal with the US Environmental Protection Agency (EPA) and the Mississippi Department of Environmental Quality (MDEQ) for the payment of fines under federal and state environmental laws with respect to this 1999 spill. Based on the discussions leading to this agreement in principal, we have recorded accrued liabilities totaling $3.0 million during 2001 and 2002. We expect to finalize the agreements with the federal and Mississippi governments during 2004; however, no assurance can be made that we will reach final agreement with the governments or the specific terms of a final agreement if one is reached. Safety and Security Regulations Our crude oil pipelines are subject to construction, installation, operating and safety regulation by the Department of Transportation ("DOT") and various other federal, state and local agencies. The Pipeline Safety Act 9 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 mandates, 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 other records to RSPA. It also authorizes RSPA to require that pipelines be modified to accommodate internal inspection devices, to mandate the installation of emergency flow restricting devices for pipelines in populated or sensitive areas, and to order other changes to the operation and maintenance of petroleum pipelines. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. On March 31, 2001, the Department of Transportation promulgated Integrity Management Plan (IMP) regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect a High Consequence Area. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. A High Consequence Area (HCA) is defined as (a) a commercially navigable waterway; (b) an urbanized area that contains 50,000 or more people and has a density of at least 1,000 people per square mile; (c) other populated areas that contain a concentrated population, such as an incorporated or unincorporated city, town or village; and (d) an area of the environment that has been designated as unusually sensitive to oil spills. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. The IMP regulation required us to prepare an Integrity Management Plan that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The risk factors to be considered include proximity to population areas, waterways and sensitive areas, known pipe and coating conditions, leak history, pipe material and manufacturer, adequacy of cathodic protection, operating pressure levels and external damage potential. The IMP regulations require that the baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. As testing is complete, we are required to take prompt remedial action to address all integrity issues raised by the assessment. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to Genesis that may not be fully recoverable by tariff increases. We have developed a Risk Management Plan as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas (USAs) along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential of a spill of crude oil on waterways. States are largely preempted from regulating pipeline safety by federal law but may assume responsibility for enforcing federal pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. Our crude oil pipelines are also subject to the requirements of the Office of Pipeline Safety of the federal Department of Transportation regulations requiring qualification of all pipeline personnel. The Operator Qualification (OQ) program required operators to develop and submit a written program. The regulations also required all pipeline operators to develop a training program for pipeline personnel and qualify them on individually covered tasks at the operator's pipeline facilities. The intent of the OQ regulations is to ensure a qualified workforce by pipeline operators and contractors when performing covered tasks on the pipeline and its facilities, thereby reducing the probability and consequences of incidents caused by human error. Our crude oil operations are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. We believe that our crude oil pipelines and trucking operations have been operated in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Various other federal and state regulations require that we train all employees in pipeline and trucking operations in HAZCOM and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request. 10 In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards such as those described above. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will spend a total of approximately $2.2 million in 2004 and 2005 for testing and rehabilitation under the IMP. We operate our fleet of leased trucks as a private carrier. Although a private carrier that transports property in interstate commerce is not required to obtain operating authority from the ICC, the carrier is subject to certain motor carrier safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations. We are subject to federal EPA regulations for the development of written Spill Prevention Control and Countermeasure (SPCC) Plans. All trucking facilities have a current SPCC Plan and employees have received training on the SPCC Plans and regulations. Annually, trucking employees receive training regarding the transportation of hazardous materials. Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration (an agency of the Department of Homeland Security, which has assumed responsibility from the DOT). None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack. Commodities regulation If we use futures and options contracts that are traded on the NYMEX, these contracts are subject to strict regulation by the Commodity Futures Trading Commission and the rules of the NYMEX. SUMMARY OF TAX CONSIDERATIONS The tax consequences of ownership of common units depend on the owner's individual tax circumstances. However, the following is a brief summary of material tax consequences of owning and disposing of common units. Partnership Status; Cash Distributions We are classified for federal income tax purposes as a partnership based upon our meeting certain requirements imposed by the Internal Revenue Code (the "Code"), which we must meet every year. The owners of common units are considered partners in the Partnership so long as they do not loan their common units to others to cover short sales or otherwise dispose of those units. Accordingly, we pay no federal income taxes, and each common unitholder is required to report on the unitholders federal income tax return the unitholder's share of our income, gains, losses and deductions. In general, cash distributions to a common unitholder are taxable only if, and the extent that, they exceed the tax basis in the common units held. Partnership Allocations In general, our income and loss is allocated to the general partner and the unitholders for each taxable year in accordance with their respective percentage interests in the Partnership (including, with respect to the general partner, its incentive distribution right), as determined annually and prorated on a monthly basis and subsequently apportioned among the general partner and the unitholders of record as of the opening of the first business day of the month to which they related, even though unitholders may dispose of their units during the month in question. A unitholder is required to take into account, in determining federal income tax liability, the unitholder's share of income generated by us for each taxable year of the Partnership ending within or with the unitholder's taxable year, even if cash distributions are not made to the unitholder. As a consequence, a unitholder's share of our taxable income (and possibly the income tax payable by the unitholder with respect to such income) may exceed the cash actually distributed to the unitholder by us. At any time incentive distributions are made to the general partner, gross income will be allocated to the recipient to the extent of those distributions. Basis of Common Units A unitholder's initial tax basis for a common unit is generally the amount paid for the common unit. A unitholder's basis is generally increased by the unitholder's share of our income and decreased, but not below zero, by the unitholder's share of our losses and distributions. 11 Limitations on Deductibility of Partnership Losses In the case of taxpayers subject to the passive loss rules (generally, individuals and closely-held corporations), any partnership losses are only available to offset future income generated by us and cannot be used to offset income from other activities, including passive activities or investments. Any losses unused by virtue of the passive loss rules may be fully deducted if the unitholder disposes of all of the unitholder's common units in a taxable transaction with an unrelated party. Section 754 Election We have made the election pursuant to Section 754 of the Code, which will generally result in a unitholder being allocated income and deductions calculated by reference to the portion of the unitholder's purchase price attributable to each asset of the Partnership. Disposition of Common Units A unitholder who sells common units will recognize gain or loss equal to the difference between the amount realized and the adjusted tax basis of those common units. A unitholder may not be able to trace basis to particular common units for this purpose. Thus, distributions of cash from us to a unitholder in excess of the income allocated to the unitholder will, in effect, become taxable income if the unitholder sells the common units at a price greater than the unitholder's adjusted tax basis even if the price is less than the unitholder's original cost. Moreover, a portion of the amount realized (whether or not representing gain) will be ordinary income. State, Local and Other Tax Considerations In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which a unitholder resides or in which we do business or own property. A unitholder may be required to file state income tax returns and to pay taxes in various states. A unitholder may be subject to penalties for failure to comply with such requirement. In certain states, tax losses may not produce a tax benefit in the year incurred (if, for example, we have no income from sources within that state) and also may not be available to offset income in subsequent taxable years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be more or less than a particular unitholder's income tax liability owed to the state, may not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. It is the responsibility of each prospective unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of the unitholder's investment in us. Further, it is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of the unitholder. Ownership of Common Units by Tax-Exempt Organizations and Certain Other Investors An investment in common units by tax-exempt organizations (including IRAs and other retirement plans), regulated investment companies (mutual funds) and foreign persons raises issues unique to such persons. Virtually all income allocated to a unitholder that is a tax-exempt organization is unrelated business taxable income and, thus, is taxable to such a unitholder. Furthermore, no significant amount of our gross income is qualifying income for purposes of determining whether a unitholder will qualify as a regulated investment company, and a unitholder who is a nonresident alien, foreign corporation or other foreign person is regarded as being engaged in a trade or business in the United States as a result of ownership of a common unit and, thus, is required to file federal income tax returns and to pay tax on the unitholder's share of our taxable income. Finally, distributions to foreign unitholders are subject to federal income tax withholding. Tax Shelter Registration The Code generally requires that "tax shelters" be registered with the Secretary of the Treasury. We are registered as a tax shelter with the Secretary of the Treasury. Our tax shelter registration number is 97043000153. Issuance of the registration number does not indicate that an investment in the Partnership or the claimed tax benefits has been reviewed, examined or approved by the Internal Revenue Service. 12 ITEM 3. LEGAL PROCEEDINGS We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on the financial condition or results of our operations. For information on the settlement of litigation with Pennzoil see Management's Discussion and Analysis - Other Matters on page 39. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the security holders during the fiscal year covered by this report. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS The Common Units are listed on the American Stock Exchange under the symbol "GEL". The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit and the amount of cash distributions paid per Common Unit.
Price Range --------------------- Cash High Low Distributions(1) ------- ------- ---------------- 2002 First Quarter...................................... $ 3.94 $ 2.31 $ -- Second Quarter..................................... $ 4.20 $ 1.80 $ -- Third Quarter...................................... $ 5.75 $ 2.00 $ -- Fourth Quarter..................................... $ 5.00 $ 4.05 $ 0.20(2) 2003 First Quarter...................................... $ 5.70 $ 4.11 $ -- Second Quarter..................................... $ 6.59 $ 4.62 $ 0.05 Third Quarter...................................... $ 7.60 $ 5.10 $ 0.05 Fourth Quarter..................................... $ 10.00 $ 6.85 $ 0.05
---------- (1) Cash distributions are shown in the quarter paid and are based on the prior quarter's activities. (2) A special distribution of $0.20 per unit was paid on December 16, 2002 to mitigate potential taxable income allocations to Unitholders. At December 31, 2003, there were 9,313,811 Common Units outstanding, including 688,811 Common Units held by our General Partner. As of December 31, 2003, there were approximately 6,500 record holders and beneficial owners (held in street name) of our Common Units. We distribute all of our Available Cash as defined in the Partnership Agreement within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves. Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which is filed as an exhibit to this Form 10-K. Our target minimum quarterly distribution is $0.20 per Common Unit. In addition to its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. In 2001, we announced that we would not pay a distribution for the fourth quarter of 2001, which would normally have been paid in February 2002. We did not pay regular distributions for 2002. We paid a special distribution in the fourth quarter of 2002 to mitigate potential taxable income allocations to unitholders. In 2003, we began paying quarterly distributions again with distributions for the first quarter of 2003 of $0.05 per unit. For the fourth quarter of 2003, we increased our distribution to $0.15 per unit (which was paid in February 2004). 13 ITEM 6. SELECTED FINANCIAL DATA The table below includes selected financial data for the Partnership for the years ended December 31, 2003, 2002, 2001, 2000, and 1999 (in thousands, except per unit and volume data).
Year Ended December 31, ---------------------------------------------------------------------------- 2003 2002 2001 2000 1999 ---------- ------------ ---------- ---------- ---------- INCOME STATEMENT DATA: Revenues: Crude oil revenues: Gathering & marketing ...................... $ 641,684 $ 639,143(1) $3,001,632 $3,897,799 $1,941,353 Pipeline ................................... 15,134 13,485 9,948 10,728 12,344 CO2 revenues ................................... 1,079 -- -- -- -- Total revenues ............................. 657,897 652,628 3,011,580 3,908,527 1,953,697 Costs and expenses: Crude oil costs: Crude oil and field operating .............. 633,776 627,966(1) 2,991,904 3,887,474 1,927,930 Pipeline operating ......................... 10,324 8,076 7,038 5,342 5,067 CO2 transportation costs ....................... 355 -- -- -- -- ---------- ------------ ---------- ---------- ---------- General and administrative expenses ............ 8,768 7,864 11,307 10,623 11,358 Depreciation and amortization .................. 4,641 4,603 5,340 6,023 6,250 Impairment of long-lived assets ................ -- -- 9,589(2) -- -- Change in fair value of derivatives .................................... -- 1,279 (1,681) -- -- Gain from sale of surplus assets ............... (236) (705) (167) (1,148) (849) Other operating charges ........................ -- 1,500 1,500 1,387 -- ---------- ------------ ---------- ---------- ---------- Total costs and expenses ................... 657,330 650,583 3,024,830 3,909,701 1,949,756 ---------- ------------ ---------- ---------- ---------- Operating income (loss) from continuing operations ................................... 34 2,045 (13,250) (1,174) 3,941 Interest expense, net ............................. (986) (1,035) (527) (1,010) (929) Minority interests effects ........................ -- -- 1 223 (602) ---------- ------------ ---------- ---------- ---------- Income (loss) in continuing operations before cumulative effect of change in accounting principle ...................... (717) 1,010 (13,776) (1,961) 2,410 Income (loss) from discontinued operations ................................... 14,039 4,082 (30,303)(2) 2,142 (78) Cumulative effect of change in accounting principle, net of minority interest effect ..................... -- -- 467 -- -- ---------- ------------ ---------- ---------- ---------- Net income (loss) ................................. $ 13,322 $ 5,092 $ (43,612) $ 181 $ 2,332 ========== ========== ========== ========== ========== Net income (loss) per common unit-basic and diluted: Continuing operations .......................... $ (0.05) $ 0.12 $ (1.57) $ (0.22) $ 0.35 Discontinued operations ........................ 1.55 0.46 (3.44) 0.24 (0.08) Cumulative effect of change in accounting principle ......................... -- -- 0.05 -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) .............................. $ 1.50 $ 0.58 $ (4.96) $ 0.02 $ 0.27 ========== ========== ========== ========== ========== Cash distributions per common unit: ............... $ 0.15 $ 0.20 $ 0.80 $ 2.28 $ 2.00
14
Year Ended December 31, ----------------------------------------------------------------------- 2003 2002 2001 2000 1999 -------- -------- -------- -------- -------- BALANCE SHEET DATA (AT END OF PERIOD): Current assets .................................. $ 88,211 $ 92,830 $182,100 $350,604 $274,717 Total assets .................................... 147,115 137,537 230,113 449,343 380,592 Long-term liabilities ........................... 7,000 5,500 13,900 -- 3,900 Minority interests .............................. 517 515 515 520 30,571 Partners' capital ............................... 52,354 35,302 32,009 82,615 53,585 OTHER DATA: Maintenance capital expenditures(3) ............. $ 4,178 $ 4,211 $ 1,882 $ 1,685 $ 1,682 Volumes-continuing operations: Crude oil gathering and marketing: Wellhead (bpd) ............................. 45,015 47,819 67,373 94,995 89,076 Bulk and exchange (bpd) .................... 11,790 25,610(1) 253,159 264,235 215,019 Crude oil pipeline (bpd) ..................... 66,959 71,870 80,408 82,092 89,298 CO2 marketing(4) (Mcf) ....................... 36,332 -- -- -- --
(1) At the end of 2001, we changed our business model to substantially eliminate bulk and exchange transactions due to relatively low margins and high credit requirements. (2) In 2001, we recorded an impairment charge of $45.1 million, with $35.5 million of that amount included in discontinued operations. This impairment charge related to goodwill and our pipeline operations. (3) Maintenance capital expenditures are capital expenditures to replace or enhance partially or fully depreciated assets to sustain the existing operating capacity or efficiency of our assets and extend their useful lives. (4) Represents average daily volume for the two month period that we owned the assets. The table below summarizes our quarterly financial data for 2003 and 2002 (in thousands, except per unit data).
2003 Quarters -------------------------------------------------------------- First Second Third Fourth --------- --------- --------- --------- Revenues - continuing operations ............................ $ 175,682 $ 146,670 $ 157,094 $ 178,451 Operating income (loss) - continuing operations ............. $ 923 $ 903 $ (1,411) $ (145) Income (loss) from continuing operations .................... 381 745 (1,568) (275) Income from discontinued operations ......................... 489 1,145 355 12,041 Net income (loss) ........................................... $ 879 $ 1,890 $ (1,213) $ 11,766 Net income (loss) per Common Unit- basic and diluted ...................................... $ 0.10 $ 0.21 $ (0.14) $ 1.28 2002 Quarters -------------------------------------------------------------- First Second Third Fourth --------- --------- --------- --------- Revenues - continuing operations ............................ $ 176,757 $ 169,681 $ 154,357 $ 147,961 Operating income (loss) - continuing operations ............. $ (239) $ 941 $ 604 $ 1,268 Income (loss) from continuing operations .................... (725) 569 34 1,087 Income (loss) from discontinued operations .................. 2,039 1,537 69 482 Net income (loss) ........................................... $ 1,314 $ 2,106 $ 103 $ 1,569 Net income (loss) per Common Unit - basic and diluted ...................................... $ 0.15 $ 0.24 $ 0.01 $ 0.18
15 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Included in Management's Discussion and Analysis are the following sections: - Overview of 2003 - Critical Accounting Policies - Results of Operations and Outlook for 2004 and Beyond - Liquidity and Capital Resources - Commitments and Off-Balance Sheet Arrangements - Other Matters - New Accounting Pronouncements In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and available cash. Our profitability depends to a significant extent upon our ability to maximize segment margin. Segment margin is calculated as revenues less cost of sales and operating expense, and does not include depreciation and amortization. A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 8 to the consolidated financial statements. Available Cash is a non-GAAP liquidity measure calculated as net income with several adjustments, the most significant of which are the elimination of gains and losses on asset sales, except those from the sale of surplus assets, the addition of non-cash expenses such as depreciation, and the subtraction of maintenance capital expenditures, which are expenditures to sustain existing cash flows but not to provide new sources of revenues. For additional information on Available Cash and a reconciliation of this measure to cash flows from operations, see "Non-GAAP Financial Measure" below. OVERVIEW OF 2003 Genesis Energy, L.P. is a Delaware limited partnership that is publicly traded on the American Stock Exchange. We operate through Genesis Crude Oil, L.P., and its subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline, USA, L.P. Our operations are managed through our general partner, Genesis Energy, Inc., a wholly-owned indirect subsidiary of Denbury Resources Inc. The general partner holds a 2% general partner interest and a 7.25% limited partner interest and public unitholders hold an aggregate 90.75% limited partner interest in Genesis Energy, L.P. We operate in three business segments - crude oil gathering and marketing, crude oil pipeline transportation and CO2 marketing. Our revenues are earned by selling crude oil and CO2 and by charging fees for the transportation of crude oil on our pipelines. Our focus is on the margin we earn on these revenues, which is calculated by subtracting the costs of the crude oil, the costs of transporting the crude oil and CO2 to the customer, and the costs of operating our assets. Our primary goal is to generate Available Cash for our unitholders. This Available Cash is then distributed quarterly to our unitholders. We are pleased with the progress we made in 2003 toward our goal of generating more stable sources of Available Cash. Two significant actions that we took in 2003 toward this goal were: - Disposing of our Texas Gulf Coast operations - Purchasing a CO2 volumetric production payment and related marketing contracts. During the fourth quarter of 2003, we closed the sale of portions of our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P. We also sold portions of our Texas pipeline system that we idled in 2002 to Blackhawk Pipeline, L.P. We abandoned in place other portions of the Texas pipeline system. The sale of these operations was the result of an initiative we started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs or risks of operation, and which segments we should invest in for future growth. As a result of these actions we recorded a gain on the disposal of these discontinued operations of $13.0 million. The sale of the Texas Gulf Coast operations to TEPPCO benefited both parties almost immediately. TEPPCO realized benefits from integrating these assets into their existing South Texas pipeline system. By selling 16 these assets, we reduced 2004 projected maintenance expenditures by $6.6 million and eliminated potential risks to the continuation of our revenue stream that may have resulted from consolidation of pipeline assets in the area. We believe that these assets had more long-term strategic benefit to TEPPCO than to us. The pipeline segments sold to Blackhawk were assets that we idled in 2002 due to declining volumes and/or risks of operation. We received no proceeds from this sale. By making the sale to Blackhawk, we eliminated costs of maintaining the assets. Blackhawk intends to convert the pipeline segments to natural gas service. The segments we abandoned in place had not been in service since 2002 and this abandonment reduces our costs for monitoring and maintenance. Additionally, this abandonment helped to offset tax gains allocated to our unitholders from the sale to TEPPCO. The carbon dioxide (CO2) volumetric production payment we purchased enables us to commence a wholesale CO2 marketing operation. We acquired this production payment, as well as related long-term CO2 industrial sales contracts, from Denbury. While this CO2 operation will have some seasonality, the cash flows from this operation will be much less volatile than those of our existing crude oil gathering and marketing operation. The funds to acquire this production payment came from the $21 million received from TEPPCO for the sale of the Texas Gulf Coast operations and the issuance of 688,811 limited partner units to our general partner in exchange for $5.0 million. Our continuing operations did not perform as well as expected. Volatility in P-Plus market prices for crude oil has historically created fluctuations in our segment margins. During 2003, we experienced positive results when P-Plus market prices increased in the early part of the year; however, a precipitous decline in segment margin during the latter half of the year offset some of the segment margin earned in the first half of the year. Revenues from our pipeline transportation operations increased primarily due to tariff increases in 2002 and 2003. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from those estimates. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (see Note 2. Summary of Significant Accounting Policies). Critical accounting policies and estimates are those that are most important to the portrayal of our financial results and positions. These policies require management's judgment and often employ the use of information that is inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, pipeline loss allowance recognition, depreciation, amortization and impairment of long-lived assets and contingent and environmental liabilities. These policies are discussed below. Revenue and Expense Accruals Information needed to record our revenues is generally available to allow us to record substantially all of our revenue-generating transactions based on actual information. The accruals that we are required to make for revenues are generally insignificant. We routinely make accruals for expenses due to the timing of receiving third party information and reconciling that information to our records. These accruals can include some crude oil purchase costs and expenses for operating our assets such as contractor charges for goods and services provided. For crude oil purchases transported on our trucks or our pipelines, we have access to the volumetric and pricing data so that we can record these transactions based on actual information. Accounting for crude oil purchases that involve third party transportation services sometimes require us to make estimates, as the necessary volumetric data is not available within the timeframe needed. By balancing our crude oil purchase and sales volumes with the change in our inventory positions, we believe we can make reasonable estimates of the unavailable data. 17 The provisions of SFAS No. 133, as amended, require that estimates be made of the effectiveness of derivatives as hedges and the fair value of derivatives. The actual results of the transactions involving the derivative instruments will most likely differ from the estimates. We make very limited use of derivative instruments; however, when we do, we base these estimates on information obtained from third parties and from our own internal records. We believe our estimates for revenue and expense items are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts. Pipeline Loss Allowance Recognition Numerous factors can cause crude oil volumes to expand and contract. These factors include temperature of both the crude oil and the surrounding atmosphere and the quality of the crude oil, in addition to inherent imprecision of measurement equipment. As a result of these factors, crude oil volumes fluctuate, which can result in losses in volumes of crude oil in the custody of the pipeline that belongs to the shippers. In order to compensate the pipeline for bearing the risk of actual losses in volumes that occur, the pipeline generally has established in its tariffs the right to make volumetric deductions from the shippers for quality and volumetric fluctuations. These deductions are referred to as pipeline loss allowances. These allowances are compared to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or expense, based on prevailing market prices at that time. When net gains occur, the pipeline company has crude oil inventory. When net losses occur, any recorded inventory on hand is reduced and the pipeline records a liability for the purchase of crude oil that it must make to replace the lost volumes. Inventories are reflected in the financial statements at the lower of the recorded value or the market value at the balance sheet date. Liabilities to replace crude oil are valued at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value. Future pipeline loss allowance revenue cannot be predicted, as it depends on factors beyond management's control such as the crude oil quality and temperatures, as well as crude oil market prices. Depreciation, Amortization and Impairment of Long-Lived Assets In order to calculate depreciation and amortization we must estimate the useful lives of our fixed assets at the time the assets are placed in service. Calculation of the useful life of an asset is based on our experience with similar assets. Experience, however, can cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. When events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, we review our assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We compare the carrying value of the fixed asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. Should the undiscounted future cash flows be less than the carrying value, we record an impairment charge to reflect the asset at fair value. Liability and Contingency Accruals We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, accruals are made. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. These estimates are revised as additional information is obtained or resolution is achieved. In 2001, we recorded an estimate of $1.5 million for the potential liability for fines related to the crude oil spill in December 1999 from our Mississippi pipeline system. After assessing information obtained in meetings with the government, this estimate was increased to a total of $3.0 million in 2002. We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. These estimates are sometimes made with the assistance of third parties involved in monitoring the remediation effort. 18 We have recorded an estimate for the additional costs expected to be incurred to complete the remediation of the site of the Mississippi crude oil pipeline spill. This estimate is based upon expectations of the additional work to be performed to meet regulatory requirements and restore the site. Because the costs of remediation and restoration for this spill are covered by insurance, we record a receivable from the insurers for a similar amount. We believe our estimates for contingent liabilities are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts. RESULTS OF OPERATIONS AND OUTLOOK FOR 2004 AND BEYOND The following table summarizes financial data by segment for the years ended December 31, 2003, 2002 and 2001 (in thousands).
Years Ended December 31, ------------------------------------------------- 2003 2002 2001 ----------- ----------- ----------- Revenues Crude oil gathering & marketing ........................... $ 641,684 $ 639,143 $ 3,001,632 Crude oil pipeline ........................................ 15,134 13,485 9,948 CO2 marketing ............................................. 1,079 -- -- ----------- ----------- ----------- Total revenues ................................................ $ 657,897 $ 652,628 $ 3,011,580 =========== =========== =========== Segment margin Crude oil gathering & marketing ........................... $ 7,908 $ 11,177 $ 9,728 Crude oil pipeline ........................................ 5,108 5,409 2,910 CO2 marketing ............................................. 724 -- -- ----------- ----------- ----------- Total segment margin .......................................... $ 13,740 $ 16,586 $ 12,638 General and administrative expenses ........................... 8,768 7,864 11,307 Depreciation and amortization ................................. 4,641 4,603 5,340 Impairment of long-lived assets ............................... -- -- 9,589 Change in fair value of derivatives ........................... -- 1,279 (1,681) Net gain on disposal of surplus assets ........................ (236) (705) (167) Other operating charges ....................................... -- 1,500 1,500 ----------- ----------- ----------- Operating income (loss) ....................................... 567 2,045 (13,250) Interest income (expense), net ................................ (986) (1,035) (527) Minority interest ............................................. -- -- 1 ----------- ----------- ----------- Income from continuing operations ............................. (419) 1,010 (13,776) Discontinued operations, net of minority interest ............. 13,741 4,082 (30,303) Cumulative effect of adoption of FAS 133 ...................... -- -- 467 ----------- ----------- ----------- Net income (loss) ............................................. $ 13,322 $ 5,092 $ (43,612) =========== =========== =========== Barrels per day from continuing operations: Crude oil wellhead ........................................ 45,015 47,819 67,373 Crude oil total ........................................... 56,805 73,429 320,532 Crude oil pipeline ........................................ 66,959 71,870 80,408
CRUDE OIL GATHERING AND MARKETING OPERATIONS The key drivers affecting our crude oil gathering and marketing segment margin include production volumes, volatility of P-Plus, volatility of grade differentials, inventory management, and credit costs. Segment margins from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels for crude oil do not necessarily bear a relationship to segment margin as absolute price levels normally impact revenues and cost of sales by equivalent amounts. Because period-to-period variations in revenues and cost of sales are not generally 19 meaningful in analyzing the variation in segment margin for gathering and marketing operations, such changes are not addressed in the following discussion. In our gathering and marketing business, we seek to purchase and sell crude oil at points along the Distribution Chain where we can achieve positive margins. We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts. We then transport the crude along the Distribution Chain for sale to or exchange with customers. Additionally, we enter into exchange transactions with third parties, generally only when the cost of the exchange is less than the alternate cost we would incur in transporting or storing the crude oil. In addition, we often exchange one grade of crude oil for another to maximize margins or meet contract delivery requirements. Prior to the first quarter of 2002, we purchased crude oil in bulk at major pipeline terminal points. These bulk and exchange transactions were characterized by large volumes and narrow profit margins on purchases and sales. Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. A significant factor affecting our gathering and marketing segment margins is the change in domestic production of crude oil. Short-term and long-term price trends impact the amount of capital that oil producers have available to maintain existing production and to invest in developing crude reserves, which in turn impacts the amount of crude oil that is available to be gathered and marketed by us and our competitors. During the last two years, posted prices for West Texas Intermediate crude oil have ranged from a low near $16 per barrel to a high of $32 per barrel. The volatility in prices over the last two years makes it very difficult to estimate the volume of crude oil available to purchase. We expect to continue to be subject to volatility and long-term declines in the availability of crude oil production for purchase. Crude oil prices in the United States are impacted by both international factors as well as domestic factors. International factors such as wars and conflicts, instability of foreign governments, and labor strikes affect prices, as do the influences in the U.S. of environmental regulations and the supply of domestic production. An increase in the market price of crude oil does not impact us to the extent many people expect. When market prices for oil increase, we must pay more for crude oil, but we normally are able to sell it for more. Most of our contracts for the purchase and sale of crude oil have components in the pricing provisions such that the price paid or received is adjusted for changes in the market price for crude oil. Often the pricing in a contract to purchase crude oil will consist of the market price component and a bonus, which is generally a fixed amount ranging from a few cents to several dollars. Typically the pricing in a contract to sell crude oil will consist of the market price component and a bonus that is not fixed, but instead is based on another market factor. This floating bonus is usually the price quoted by Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed and P-Plus floats in the sales contracts, the margin on individual transactions can vary from month-to-month depending on changes in the P-Plus component. P-Plus does not necessarily move in correlation with the price of crude oil in the market. P-Plus is affected by numerous factors such as future expectations for changes in crude oil prices, such that crude oil prices can be rising, but P-Plus can be decreasing. The table below shows the average P-Plus and the average posted price for West Texas Intermediate (WTI) as posted by Koch Supply & Trading, L.P. by quarter in 2003, 2002 and 2001, based on the simple averaging of the monthly averages. 20
Quarter P-Plus WTI Posting ------- ------ ----------- 2001 First $3.9053 $25.7808 Second $2.7097 $24.8163 Third $3.4173 $23.6087 Fourth $2.8517 $17.2577 2002 First $2.7953 $18.4846 Second $3.3015 $23.0634 Third $3.4400 $25.0589 Fourth $3.5060 $24.9902 2003 First $4.1336 $30.6306 Second $4.6063 $25.7125 Third $4.0336 $27.0065 Fourth $3.4881 $27.9642
As can be seen from this table, changes in P-Plus do not necessarily correspond to changes in the market price of oil. An example is the decline in P-Plus between the third and fourth quarters of 2003 when the WTI posting increased. This unpredictable volatility in P-Plus can create volatility in our earnings. A few purchase contracts and some sale contracts also include a component for grade differentials. The grade refers to the type of crude oil. Crude oils from different wells and areas can have different chemical compositions. These different grades of crude oil will appeal to different customers depending on the processing capabilities of the refineries that ultimately process the crude oil. We may buy crude oil under a contract where we considered the typical grade differences in the market when we set the fixed bonus. If we then sell the oil under a contract with a floating grade differential in the formula, and that grade differential fluctuates, then we can experience an increase or decrease in our margin from that oil purchase and sale. The table below shows the grade differential between West Texas Intermediate grade crude oil and West Texas Sour grade crude oil, using the monthly averages for each quarter of 2001, 2002 and 2003, and the differential between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for the same periods.
WTI/WTS WTI/LLS Quarter Differential Differential ------- ------------ ------------ 2001 First $(3.694) $(0.137) Second $(3.810) $(0.149) Third $(2.047) $(0.081) Fourth $(2.088) $ 0.180 2002 First $(1.536) $ 0.348 Second $(1.218) $ 0.090 Third $(1.028) $(0.323) Fourth $(1.772) $ 0.004 2003 First $(2.361) $ 0.460 Second $(3.189) $(0.216) Third $(2.443) $(0.234) Fourth $(2.711) $ 0.320
As can be seen from this table, the WTI/WTS market differential varied from $1.028 per barrel in the third quarter of 2002 to $3.810 per barrel in second quarter of 2001. The WTI/LLS market differential varied from a negative $0.323 per barrel in the third quarter of 2002 to a positive $0.460 in the first quarter of 2003. This volatility in grade differentials can affect the volatility of our gathering and marketing segment margin. 21 Our purchase and sales contracts are primarily "Evergreen" contracts, which means they continue from month to month unless one of the parties to the contract gives 30-days notice of cancellation. In order to change the pricing in a fixed bonus contract, we would have to give 30-days notice that we want to cancel or renegotiate the contract. This notice time requirement, therefore, means that at least a month will pass before the fixed bonus can be reduced to correspond with a decrease in the P-Plus component of the related sales contract. In this case, our margin would be reduced until such a change is made. Because of the volatility of P-Plus, it is not practical to renegotiate every purchase contract for every change in P-Plus. So segment margins from the sale of the crude oil may be volatile as a result of these timing differences. Another factor that can contribute to volatility in our earnings is inventory management. Generally contracts for the purchase of crude oil will state that we will buy all of the production for the month from a particular well. We generally aggregate the volumes purchased from numerous wells and deliver it into a pipeline where we sell the crude oil to a third party. While oil producers can make estimates of the volume of oil that their wells will produce in a month, they cannot state absolutely how much oil will be produced. Our sales contracts typically state a specific volume to be sold. Consequently, if a well produces more than expected, we will purchase volumes in a month that we have not contracted to sell. These volumes are then held as inventory and are sold in a later month. Should the market price of crude oil fluctuate while we have these inventory volumes, we may have to recognize a loss in our financial statements should the market price fall below the cost of the inventory. Should market prices rise, then we will realize a gain when we sell the unexpected volume of inventory in a later month at higher prices. We make every effort to limit our exposure to these price fluctuations by minimizing inventory volumes. Year Ended December 31, 2003 as Compared to Year Ended December 31, 2002 Gathering and marketing segment margins decreased $3.3 million or 29% to $7.9 million for the year ended December 31, 2003, as compared to $11.2 million for the year ended December 31, 2002. A 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $5.3 million decrease in segment margin, was the primary reason for this decrease. Factors offsetting this decrease were: - A $1.6 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and - a $0.4 million decrease in field operating costs, primarily from a $0.5 million decrease in payroll and benefits, offset by a $0.1 million increase in repair costs. The decreased payroll-related costs can be attributed to an approximate 6 percent decrease in the wellhead volumes. The increase in repair costs is attributable primarily to repairs at truck unloading stations. Although P-Plus declined significantly in the latter half of 2003, the average for 2003 of $4.065 per barrel was 25% higher than the average for 2002 of $3.261 per barrel. This price increase was not enough however to offset the decline in volumes. We changed our business model in 2002 to substantially eliminate our bulk and exchange activity due to the relatively low margins and high credit requirements for these transactions. Additionally, we reviewed our wellhead purchase contracts to determine whether margins under those contracts would support higher credit costs. In some cases, contracts were cancelled. These volume reductions began in late 2001 and continued into the first half of 2002. Volumes beginning in the third quarter of 2002 have remained relatively stable at an average of 57,500 barrels per day. For the fourth quarter of 2003, daily volumes were 61,400 barrels. The change in our business model was the primary reason crude oil gathering and marketing volumes decreased by 23%. Field operating costs primarily consist of the costs to operate our fleet of 49 trucks used to transport crude oil, and the costs to maintain the trucks and assets used in the crude oil gathering operation. Approximately 55% of these costs are variable and decline when volumes decline. Such costs include payroll and benefits (as drivers are paid on a commission basis based on volumes), maintenance costs for the trucks (as we lease the trucks under full service maintenance contracts under which we pay a maintenance fee per mile driven), and fuel costs. Fixed costs include the base lease payment for the vehicle, insurance costs and costs for environmental and safety related items. 22 Year Ended December 31, 2002 as Compared to Year Ended December 31, 2001 Gathering and marketing segment margins increased $1.4 million or 15% to $11.2 million for the year ended December 31, 2002, as compared to $9.7 million for the year ended December 31, 2001. The factors increasing segment margin were: - an $18.4 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and - an $0.8 million decrease in credit costs primarily due to the reduction in bulk and exchange transactions. Largely offsetting these increases were: - a 77 percent decrease in wellhead, bulk and exchange purchase volumes between 2001 and 2002, resulting in a decrease in segment margin of $17.1 million; and - a $0.7 million increase in field operating costs, primarily from a $0.3 million increase in payroll and benefits, a $0.2 million increase in repair costs, a $0.1 million increase in vehicle lease costs, and a $0.1 million increase in insurance costs. The increased payroll-related costs can be attributed to an increase in benefit costs and an increase in the miles driven in our trucks. The increased lease costs are attributable to increases in the number of vehicles and in the miles driven. The increase in repair costs is attributable primarily to repairs at truck unloading stations. The increased insurance costs reflect a combination of changes in the insurance market and our loss history. As discussed previously, we eliminated transactions with low margins and high credit costs. These volume reductions were the primary reasons gathering and marketing volumes decreased by 77% in the 2002 period. Outlook for 2004 and Beyond Volatility in P-Plus will continue. During 2004, we expect our crude oil gathering and marketing business to generate at least as much segment margin as it did in 2003; however, no assurance can be made that this will occur. Our plans include increasing volumes by acquiring new production and production currently being gathered by other parties. CRUDE OIL PIPELINE OPERATIONS We operate three common carrier pipeline systems in a five state area. We refer to these pipelines as our Texas System, Mississippi System and Jay System. Volumes shipped on these systems for the last three years are as follows (barrels per day):
Pipeline System 2003 2002 2001 --------------- ---- ---- ---- Texas 43,388 47,987 43,322 Mississippi 8,443 7,426 17,792 Jay 15,128 16,455 19,294
In 2003, we sold or abandoned significant portions of our Texas System. The segments we retained and continue to operate are from West Columbia to Webster, Cullen Junction to Webster, and from Webster to Texas City, and Webster to a shipper's facility in Houston. Information on the segments sold or abandoned is discussed in the section "Discontinued Operations" below. The following information pertains only to continuing operations. Volumes on our Texas System averaged 43,388 barrels per day in 2003. The crude oil that enters our system comes to us at West Columbia and Cullen Junction where we have connections to TEPPCO's South Texas System and at Webster where we have a connection with another pipeline. Under the terms of our sale to TEPPCO of portions of the pipeline, we have a joint tariff with TEPPCO through September 2004 under which we earn $0.40 per barrel on the majority of the barrels we deliver to the shipper's facilities and $0.50 per barrel on heavier crude oil we deliver. Most of the volume being shipped on our Texas System goes to three refineries on the Texas Gulf Coast. We are still shipping most of the same volumes that we were shipping before the sale to TEPPCO, however our tariff revenue is much less than before the sale, as we ship the crude oil a shorter distance. 23 The Mississippi System is best analyzed in two segments. The first segment is the portion of the pipeline that begins in Soso, MS and extends to Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest. The segment from Soso to Liberty has also been improved to handle the increased volumes produced by Denbury and transported on the pipeline. In order to handle future increases in production volumes in the area that are expected, we have made capital expenditures for tank, station and pipeline improvements and we will need to make further improvements. See Capital Expenditures under "Liquidity and Capital Resources" below. The second segment of the pipeline from Liberty to near Baton Rouge, LA has been out of service since February 1, 2002 while a connecting carrier tested its pipeline. The connecting carrier has decided not to reactivate its pipeline, so we will displace the crude oil in this segment with inhibited water until the connecting carrier either make repairs or we identify an alternative use for this segment. The cost of this displacement is being paid for by the owner of the crude oil. In 2003, this segment made no contribution to pipeline revenues. In 2002 and 2001, this segment of pipeline contributed $0.1 million and $1.5 million, respectively, to pipeline revenues. Volumes on this segment in 2001 were over 14,400 barrels per day. The Jay pipeline system in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Volumes have declined from an annual average of 19,294 per day in 2001, to 16,455 in 2002 to 15,128 in 2003. Many of the costs to operate our pipeline are fixed costs, including the costs of compliance with environmental regulations and the costs of insurance, so the decline in volumes has necessitated increases in tariffs. The only shipper on the largest portion of the pipeline has agreed to tariff rate increases in 2002 and 2003 that have helped offset the declines in the volumes and increased costs of operating this pipeline. Historically, the largest operating costs in our crude oil pipeline segment have consisted of personnel costs, power costs, maintenance costs and costs of compliance with regulations. Some of these costs are not predictable, such as failures of equipment, or are not within our control, like power cost increases. We perform regular maintenance on our assets to keep them in good operational condition to minimize any cost increases. Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 Pipeline segment margin decreased $0.3 million or 6% to $5.1 million for the year ended December 31, 2003, as compared to $5.4 million for the year ended December 31, 2002. The factors decreasing pipeline segment margin were: - a 7 percent decrease in throughput between the two years, resulting in a revenue decrease of $0.8 million; and - a $1.9 million increase in pipeline operating costs in 2003. In the third quarter we recorded an asset retirement obligation of $0.7 million related to an offshore pipeline. Pipeline operating costs increased $0.1 million for personnel and benefits costs related to addition as of operations staff in Mississippi and additions of staff engineers, and $0.1 million for costs associated with work vehicles for the new staff. Costs associated with maintenance of right-of ways, including clearing of tree canopies, and costs for testing under pipeline integrity regulations increased a combined $0.2 million. In 2003, we increased safety training for pipeline operations personnel at a cost of $0.3 million. Insurance costs increased $0.2 million due to the combination of insurance market conditions and our loss history. Other operating costs, including power costs increased a total of $0.3 million. Partially offsetting these decreases were the following factors: - a 22 percent increase in the average tariff on shipments resulting in a $2.3 million increase in revenue; and - a $0.1 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices resulting in more revenue on these volumes. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 Pipeline segment margin increased $2.5 million or 86% to $5.4 million for the year ended December 31, 2002, as compared to $2.9 million for the year ended December 31, 2001. The factors increasing pipeline segment margin were: 24 - a 35 percent increase in the average tariff on shipments resulting in a $2.9 million increase in revenue; and - a $1.6 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of revising pipeline tariffs to increase the amount of the pipeline loss allowance imposed on shippers, and the recognition of pipeline loss allowance volumes, measurement gains net of measurement losses, and crude quality deductions as inventory. Partially offsetting these increases were: - an 11 percent decrease in throughput between the two years, resulting in a revenue decrease of $1.0 million; and - a $1.0 million increase in pipeline operating costs in 2002 primarily due to greater expenditures for personnel and benefits, for maintenance of right-of-ways including clearing of tree canopies and costs associated with residential and commercial development around our pipelines, for testing under the pipeline integrity management regulations, for tank and station maintenance projects, for safety, training and related projects, for liability and property damage insurance, offset by lower costs for remote monitoring and control. Personnel and benefits costs increased $0.3 million primarily as a result of additions to the operations staff in Mississippi and costs associated with work vehicles for the new staff added $0.1 million. Costs associated with maintenance of right of ways and testing under pipeline integrity regulations increased a combined $0.1 million. In 2002, we increased safety training for our pipeline operations personnel at a cost of $0.1 million. Additionally we undertook a project to add Global Positioning Satellite information to our pipeline maps as required pursuant to pipeline safety regulations. Expenses incurred on this project in 2002 totaled $0.2 million. Insurance costs increased by $0.3 million due to the combination of insurance market conditions and our loss history. Our remote monitoring and control costs were lower by $0.1 million as we completed the transition in early 2002 from a more expensive service. Outlook for 2004 and Beyond After September 2004, we may continue to provide capacity to transport crude oil on our Texas System from Webster to Texas City and Houston. We expect to cease using the West Columbia to Webster segment and the Cullen Junction to Webster segment for crude oil service, as volumes shipped do not support the costs we would expect to incur to test and repair those segments of pipeline under the integrity management regulations. See discussion of the integrity management regulations in Safety Regulation under in "Item 1". If we continue to ship crude oil from Webster after September 2004, we would expect that we will receive it at Webster from new connections to other pipelines and receive less tariff income from those shipments than we are receiving under the current joint tariff with TEPPCO. We are also examining strategic opportunities to place the remaining segments in alternative service after the arrangement with TEPPCO expires. We expect that volumes may decline in 2004 as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's pipeline systems; however, those effects may not occur until the summer of 2004 when TEPPCO finishes its integration and connection of the segments acquired from us. As discussed above, the primary shipper on the segment of our Mississippi pipeline from Liberty to near Baton Rouge advised us in February 2004 that it does not have plans to reinstate shipments on this segment of pipeline. We currently plan to temporarily idle this segment of pipeline by removing the crude oil from the line while we evaluate future plans for this segment. Any future plans in crude oil service will require sufficient volumes being available to be transported on this segment of pipeline to justify the costs to perform the integrity testing and possible upgrading that may be necessary as a result of that testing. Future plans for this segment may include transportation of petroleum products or natural gas. Denbury is the largest oil and gas producer in Mississippi. Our Mississippi pipeline is adjacent to several of Denbury's existing and prospective oil fields. There may be mutual benefits to Denbury and us due to this common production and transportation area. Because of this relationship, we may be able to obtain certain commitments for increased crude oil volumes, while Denbury may obtain the certainty of transportation for its oil production at competitive market rates. As Denbury continues to acquire and develop old oil fields using CO2 based tertiary recovery operations, Denbury would expect to add crude oil gathering and CO2 supply infrastructure 25 to these fields. Further, as the fields are developed over time, it may create increased demand for our crude oil transportation services. The production shipped from oil fields surrounding our Jay system is a combination of new fields with estimated short production lives and older fields that have been producing for twenty to thirty years and are in the late stages of economic life. We believe that the highest and best use of the Jay system would be to convert it to natural gas service. We continue to review strategic alternatives with other parties in the region to explore this opportunity. This initiative is in a very preliminary stage. Part of the process will involve finding alternative methods for us to continue to provide crude oil transportation services in the area. While we believe this initiative has long-term potential, it is not expected to have a substantial impact on us during 2004 or 2005. Pipeline segment margins from continuing operations should remain flat or decline slightly in 2004. We expect volume increases on the Mississippi system and the tariff increases on the Jay system to substantially offset increases in fixed costs, including the costs for testing under the integrity management program. CARBON DIOXIDE (CO2) OPERATIONS In November 2003, we acquired a volumetric production payment of 167.5 Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the production payment, Denbury also assigned to us three of their existing long-term CO2 contracts with industrial customers. Denbury owns the pipeline that is used to transport the CO2 to our customers as well as to its own tertiary recovery operations. The industrial customers treat the CO2 and transport it to their own customers. The primary industrial applications of CO2 by these customers include beverage carbonation and food chilling and freezing. Based on Denbury's experience, we can expect some seasonality in our sales of CO2, as the dominant months for beverage carbonation and freezing food are from April to October, when warm weather drives up demand for beverages and the approaching holidays increase demand for frozen foods. The average daily Mcf for each month in 2003, 2002 and 2001 purchased under these contracts was as follows:
Month 2003 2002 2001 ----- ---- ---- ---- January 35,533 35,802 32,185 February 38,441 38,770 38,458 March 38,292 39,342 32,761 April 41,683 37,295 36,470 May 42,092 37,890 37,944 June 42,898 37,296 39,342 July 43,220 37,125 40,148 August 42,048 39,799 41,042 September 43,564 39,746 41,159 October 42,810 40,844 41,489 November 38,767 38,568 42,349 December 33,975 34,835 38,234
The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012, and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee from us of $0.16 per Mcf, subject to inflationary adjustments, for those transportation services. The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The maximum daily contract quantity per year in the contracts totals 48,750 Mcf. Under the minimum take or pay volumes, the customers must purchase a total of 14,468 Mcf per day whether received or not. Any volume purchased under the take-or-pay provision in any year can then be recovered in a future year as long as 26 the minimum requirement is met in that year. In the three years ended December 31, 2003, all three customers have purchased more than their minimum take-or-pay quantities, as can be seen in the table above. The three industrial contracts extend through 2010, 2012 and 2015. The sales contracts contain provisions for inflationary adjustments to sales prices based on the Producer Price Index, with a minimum price. During the two months we owned the CO2 assets in 2003, we earned revenues of $1.0 million and segment margin of $0.7 million. We expect to generate approximately $5 million of annual segment margin from this business during the first five years. The purchase of these assets provides us with diversity in our asset base and a stable long-term source of cash flow. DISCONTINUED OPERATIONS In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc.. We received no proceeds from the sale to Blackhawk. Other remaining segments not sold to these parties were abandoned in place. The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs and risks of operation. As a result of this evaluation we determined that parts of our Texas Gulf Coast operations were of more strategic value to TEPPCO than to us. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks. By selling these assets, we eliminated approximately $6.6 million of capital expenditures that we might have had to make depending on the results of IMP testing. TEPPCO paid us $21.6 million for the assets it acquired. We incurred transaction costs of $0.4 million which reduced the net proceeds to $21.2 million. TEPPCO also assumed responsibility for $0.6 million of unpaid royalties related to the crude oil purchase and sale contracts it assumed. We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period. We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to the sale date, subject to certain conditions. TEPPCO will pay the first $25,000 for each environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of that amount up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO for environmental matters in connection with this transaction will cease in ten years. We do not expect the effects of this indemnification to have a material effect on our results of operations in the future. During 2003, we recorded $0.4 million in termination benefits related to this sale. These benefits included retention bonuses and severance pay for employees affected by the sale. Under the terms of the sale to Blackhawk, we agreed to provide transition services through March 31, 2004. These transition services are not significant as the pipeline is idle. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years. 27 Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:
Year Ended December 31, --------------------------------------- 2003 2002 2001 --------- --------- --------- Revenues: Gathering and marketing ........................................... $ 263,930 $ 252,452 $ 324,371 Pipeline .......................................................... 6,480 6,726 4,247 --------- --------- --------- Total revenues ................................................. 270,410 259,178 328,618 Costs and expenses: Crude costs ....................................................... 256,986 243,262 313,202 Field operating costs ............................................. 4,718 4,535 4,379 Pipeline operating costs .......................................... 5,846 4,852 3,859 General and administrative ........................................ 282 425 384 Depreciation and amortization ..................................... 1,864 1,210 2,206 Change in fair value of derivatives ............................... -- 815 (578) Net gain on disposal of surplus assets ............................ -- (3) -- Impairment of long-lived assets ................................... -- -- 35,472 --------- --------- --------- Total costs and expenses ....................................... 26,696 255,096 358,924 --------- --------- --------- Operating income from discontinued operations .................. 714 4,082 (30,306) --------- --------- --------- Net proceeds from asset sales ........................................ 21,240 -- -- Net book value of assets sold ........................................ 8,212 -- -- --------- --------- --------- Gain on disposal of assets ........................................... 13,028 -- -- --------- --------- --------- Income from operations from discontinued Texas System before minority interests .................................. $ 13,742 $ 4,082 $ (30,306) ========= ========= =========
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2003 declined by $3.6 million, with $2.4 million of the decline resulting from crude oil gathering and marketing operations, and the remainder from pipeline operations. Margin from discontinued crude oil gathering and marketing operations declined due to the following: - an $0.8 million decrease in margin due to an decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; - a 15 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $1.4 million decrease in margin; and - a $0.2 million increase in field operating costs from termination benefits. Pipeline margin from discontinued operations decreased by $1.2 million due to the following: - a 2 percent decrease in the average tariff on shipments resulting in a $0.1 million decrease in revenue; - an 11 percent decrease in throughput between the two years, resulting in a $0.5 million revenue decrease; and - a $1.0 million increase in pipeline operating costs in 2003. Included in the pipeline operating costs in 2003 is $0.7 million for demolition and disposal costs for tanks and other equipment that were not sold and no longer had any use to us. We chose to perform this demolition in 2003 to reduce the taxable gain that would be allocated to many of our unitholders from the sale to TEPPCO. Also included in 2003 is $0.2 million for termination benefits incurred as a result of the sale to TEPPCO. Other operating costs increased a total of $0.1 million. These decreases were partially offset by a $0.4 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices. 28 General and administrative expenses include the direct costs of individuals involved only with the assets sold. The decrease in these costs resulted from the termination of those persons from our employment as a result of the sale. The increase in depreciation in 2003 as compared to 2002 resulted from the elimination of the remaining book value of assets not sold that no longer had any use to us. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2002 declined by $0.6 million. This amount is the net result of a $2.1 million decrease in margin from crude oil gathering and marketing operations, and a $1.5 million increase in margin from pipeline operations. Margin from crude oil gathering and marketing operations declined due to the following: - a 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a decrease in margin of $2.5 million; and - $0.1 million increases in both field operating and credit costs. Partially offsetting these decreases was a $0.6 million increase in margin due to a decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale. Pipeline margin increased by $1.5 million due to the following: - a 34 percent increase of in the average tariff on shipments resulting in a $1.4 million increase in revenue; - a 10 percent increase in throughput between the two years, resulting in a $0.4 million revenue increase; and - an increase in revenues from sales of pipeline loss allowance barrels of $0.7 million primarily as a result of higher crude oil market prices resulting in more revenue on these volumes. Partially offsetting these increases was a $1.0 million increase in pipeline operating costs in 2002. These increases included a $0.2 million increase in costs associated with maintenance of right of ways and testing under pipeline integrity regulations; tank and station maintenance expenses increased $0.2 million and safety training for our pipeline operations personnel increased $0.2 million. Insurance costs increased $0.1 million and the mapping project added $0.3 million to costs. In 2001, we recorded impairment of $35.5 related to the assets that were sold or abandoned in 2003. This impairment reduced the depreciation recorded in 2002. OTHER COSTS AND INTEREST Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 General and administrative expenses. General and administrative expenses increased $0.9 million in 2003 from the 2002 level. Corporate governance costs including legal and consultant costs related to compliance with the Sarbanes-Oxley Act of 2002, increased directors fees and higher directors and officers insurance costs added $0.4 million. Other general and administrative costs increased by $0.1 million. Two other factors contributing to this increase were the write-off of $0.2 million of unamortized legal and consultant costs related to credit agreement with Citicorp and a non-cash charge of $0.2 million related to our new stock appreciation rights program for employees and directors (see Note 14 to the consolidated financial statements). The write-off of unamortized costs was necessitated by the replacement of the Citicorp credit facility in 2003 with a credit facility with Fleet National Bank. Under our bonus program, bonuses were eliminated unless distributions were being paid, which resulted in no accrual in 2002. We expect general and administrative expenses in 2004 to remain level with those of 2003. Consultant costs related to the internal documentation and assessment provisions of the Sarbanes-Oxley Act are expected to increase over 2003 levels, offsetting the 2003 write-off of credit facility costs. Change in fair value of derivatives. We designated our contracts as normal purchases and sales under the provisions for that treatment in SFAS No. 133. We did not engage in any derivative transactions during 2003, and 29 would expect to do so in 2004 only as needed. During 2002, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million. Other operating charges. In 2002, we reached an agreement in principle with the federal and state regulatory authorities regarding the fines we would pay related to the spill that occurred in December 1999 in Mississippi. The cost to us under the agreement is expected to be $3.0 million. In the fourth quarter of 2001 we accrued $1.5 million for this potential fine and in the third quarter of 2002 another $1.5 million was accrued. Interest expense, net. In 2003, our net interest expense decreased by $0.1 million. The primary factor was a decrease in March 2003 of the size of our credit facility from $80 million to $65 million. In 2002, the larger amount of the credit facility resulted in higher commitment fees. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 General and administrative expenses. General and administrative expenses decreased $3.4 million in 2002 from the 2001 level. Changes in personnel costs primarily due to the elimination of bulk and exchange activities reduced general and administrative expenses $2.3 million, and charges from our bonus program were $0.8 million less in 2002. The remaining decrease of $0.3 million is attributable to decreases in expenses for legal, tax and other professional services, offset by small increases in administrative insurance costs and contract labor costs. Depreciation, amortization and impairment. Depreciation and amortization expense decreased $1.7 million in 2002 from the 2001 level. As a result of the impairment of our pipeline assets in 2001, the value to be depreciated was reduced. The impairment recorded in 2001 was $9.6 million and related primarily to goodwill. Change in fair value of derivatives. As a result of the significant reduction in our bulk and exchange activities at December 31, 2001, and a review of contracts existing at December 31, 2002, we determined that substantially all of our contracts did not meet the requirement for treatment as derivative contracts under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended and interpreted). The contracts were designated as normal purchases and sales under the provisions for that treatment in SFAS No. 133. As a result, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million in 2002. Net gain on disposal of surplus assets. In 2002, we disposed of our seats on the NYMEX for $1.7 million, resulting in a gain of $0.5 million. The changes we made in our business model to reduce our bulk and exchange activities eliminated our reasons for owning the NYMEX seats. Additionally, in 2002, we sold surplus land, a building and surplus vehicles, resulting in additional cumulative net gains of $0.2 million. In 2000, we leased our tractor/trailer fleet from Ryder Transportation Services. The majority of the existing fleet was sold in 2000 and 2001. Cash proceeds of $0.4 million and a gain of $0.1 million in 2001 were realized in 2001 from this sale. Interest expense, net. In 2002, the Partnership had an increase in its net interest expense of $0.5 million. In 2001, the Partnership paid commitment fees on the unused portion of its $25 million facility with BNP Paribas. In the 2002 period, the Partnership paid commitment fees on the unused portion of its credit facility of $130 million in the first pat of the year and $80 million thereafter. The larger amount of the credit facility resulted in substantially higher commitment fees in 2002. LIQUIDITY AND CAPITAL RESOURCES Cash Flows Our primary sources of cash flows are operations, credit facilities, and in 2003, proceeds from the sale of a portion of our operations. Additionally in 2003, we issued limited partner interests to our general partner and received cash. Our primary uses of cash flows are capital expenditures and distributions. A summary of our cash flows for the years ended December 31, 2003, 2002 and 2001 is as follows (in thousands):
Year Ended December 31, ----------------------------------------------- 2003 2002 2001 ------------ ----------- ------------ Cash provided by (used in): Operating activities................................. $ 4,693 $ 7,417 $ 18,156 Investing activities................................. $ (6,994) $ (1,963) $ (1,429) Financing activities................................. $ 4,099 $ (10,160) $ (16,458)
30 Operating. Net cash from operating activities for each year have been comprised of the following (in thousands):
Year Ended December 31, ------------------------------------- 2003 2002 2001 -------- -------- -------- Net income ............................................. $ 13,322 $ 5,092 $(43,612) Depreciation, amortization and impairment .............. 7,535 6,549 52,630 Gain on sales of assets ................................ (13,264) (708) (167) Derivative related non-cash adjustments ................ 39 2,055 (2,726) Other non-cash items ................................... 229 1,500 1,601 Changes in components of working capital, net .......... (3,168) (7,071) 10,430 -------- -------- -------- Net cash from operating activities .................. $ 4,693 $ 7,417 $ 18,156 ======== ======== ========
Our operating cash flows are affected significantly by changes in items of working capital. We have had situations where other parties have prepaid for purchases or paid more than was due, resulting in fluctuations in one period as compared to the next until the party recovers the excess payment. While this happens infrequently, we did incorrectly receive $2.4 million in 2001 that was not repaid until 2003. During the 2001 period while we were actively engaged in bulk and exchange activities, our cash flows were affected by the differences in the timing between receiving the cash effects of derivative transactions and recording those transactions in net income. Affecting all periods is the timing of capital expenditures and their effects on our recorded liabilities. Cash management in the crude oil gathering and marketing business functions as follows. All purchases and sales are settled monthly with payment on the 20th of the following month. We receive payment for sales by wire transfer on the 20th. Approximately 75% of the obligations for purchases are also paid by wire transfer on the 20th. The remaining 25% of purchases are paid for by check. These checks, primarily to royalty owners and small oil companies, generally take five or six days to clear our bank account. This payment cycle provides several benefits to us. We know that substantially all of our receivables for crude oil sales will be collected on the 20th. We also defer payment until checks that were mailed clear our checking accounts. Our borrowings, and therefore our interest costs, are reduced for this short time period each month following the 20th. Similarly, tariffs are billed monthly and require payment ten days after the invoice date. Therefore collection of our pipeline accounts receivable is very rapid. Because shippers generally want to continue shipping, these receivables are generally paid quickly by our customers. Our accounts receivable settle monthly and collection delays generally relate only to discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered. Of the $66.7 million aggregate receivables on our consolidated balance sheet at December 31, 2003, approximately $65.4 million, or 98.1%, were less than 30 days past the invoice date. Investing. Cash flows used in investing activities in 2003 were $7.0 million as compared to $2.0 million in 2002. In 2003 we sold portions of our Texas pipeline system as well as other assets for $22.3 million net, and we expended $24.4 million to acquire the CO2 assets. Additionally we expended $4.9 million for other capital improvements. These expenditures included improvements on our Mississippi pipeline system to handle increased volumes more efficiently and effectively, additions and improvements totaling approximately $1.5 million on the Texas assets sold to TEPPCO in October 2003 and other equipment improvements. In 2002 we expended $4.2 million for property and equipment additions. These expenditures included replacement of pipe in Mississippi and Texas and upgrades to pipeline stations in Mississippi to handle larger volumes of crude oil throughput, including building new tanks. Offsetting these expenditures in 2002, were sales of surplus assets from which we received $2.2 million. In early 2002, we sold our two seats on the NYMEX for $1.7 million as discussed above. We also received $0.5 million from the sale of excess land with a building. In 2001, we expended $1.9 million for property and equipment, primarily in our pipeline operations. We received $0.5 million from the sale of tractors and trailers that were no longer needed as the fleet was replaced with new equipment leased from Ryder Transportation Inc. See additional detail on capital expenditures below. Financing. In 2003, financing activities provided net cash of $4.1 million. In November 2003, our general partner acquired from us 688,811 newly-issued Common Units and a proportionate general partner interest for $5.0 million. We also increased our outstanding debt by $1.5 million. We utilized $1.1 million of these funds to pay 31 fees related to the new credit facility with Fleet National Bank. Distributions to our partners utilized $1.3 million. Net cash expended for financing activities was $10.2 million in 2002 as compared to $16.5 million in 2001. In 2002 we reduced long-term debt outstanding at year end by $8.4 million from the balance at December 31, 2001. We also paid a special distribution of $0.20 per unit in December 2002, which utilized $1.8 million of cash. In 2001, we reduced debt by $8.1 million from the balance at December 31, 2000, and paid four quarterly distributions in the amount of $0.20 per unit each, which utilized $7.0 million of cash. Capital Expenditures A summary of our capital expenditures in the three years ended December 31, 2003, 2002, and 2001 is as follows (in thousands):
Year Ended December 31, ----------------------------------------- 2003 2002 2001 --------- --------- --------- Maintenance capital expenditures: Texas pipeline system ................................... $ 1,588 $ 1,638 $ 1,242 Mississippi pipeline system ............................. 1,684 1,838 222 Jay pipeline system ..................................... 213 43 10 Crude oil gathering assets .............................. 307 241 167 Administrative assets ................................... 384 451 241 --------- --------- --------- Total maintenance capital expenditures ............... 4,176 4,211 1,882 Growth capital expenditures: Mississippi pipeline system ............................. 76 -- -- Crude oil gathering assets .............................. 658 -- -- CO2 assets .............................................. 24,401 -- -- --------- --------- --------- Total growth capital expenditures .................... 25,135 -- -- --------- --------- --------- Total capital expenditures ........................ $ 29,311 $ 4,211 $ 1,882 ========= ========= =========
Maintenance capital expenditures in 2003 included a total of $0.5 million for installation of pipeline satellite monitoring capabilities on all three systems. Administrative asset expenditures included computer hardware and software. In the first half of 2003, we continued to upgrade the West Columbia to Markham segment of our Texas pipeline. The expenditures on the Mississippi system included additional improvements to the pipeline from Soso to Gwinville, where the crude oil spill had occurred in December 1999, to restore this segment to service. We also improved the pipeline from Gwinville to Liberty to be able to handle increased volumes on that segment by upgrading pumps and meters and completing additional tankage. Growth capital expenditures in 2003 included the acquisition of a condensate storage facility in Texas that was subsequently sold to TEPPCO and the acquisition of the CO2 assets from Denbury. Although we have no commitments to make capital expenditures, based on the information available to us at this time, we currently anticipate that our capital expenditures will be as follows (in thousands):
2004 2005 2006 ---- ---- ---- Maintenance capital expenditures: Texas System $ 106 $ 396 $ 199 Mississippi System 455 1,593 969 Jay System 30 145 75 Other 167 60 60 -------- --------- --------- Total $ 758 $ 2,194 $ 1,303 ======== ========= =========
In 2004, we expect the expenditures on our Texas system to relate primarily to corrosion control and in 2005 and 2006, to improvements to our control and monitoring system. The maintenance capital expenditure estimates for our Mississippi system include corrosion control expenditures, minor facility improvements and rehabilitation of the pipeline as a result of integrity management test results, as discussed below. 32 Complying with Department of Transportation Pipeline Integrity Management Program (IMP) regulations has been and will be a significant driver in determining the amount and timing of our capital expenditure requirements. On March 31, 2001, the Department of Transportation promulgated the IMP regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect High Consequence Areas (HCA). The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative technology. An HCA is defined as (a) a commercially navigable waterway; (b) an urbanized area that contains 50,000 or more people and has a density of at least 1,000 people per square mile; (c) other populated areas that contain a concentrated population, such as an incorporated or unincorporated city, town or village; and (d) an area of the environment that has been designated as unusually sensitive to oil spills. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. In accordance with the IMP regulations, we prepared a written Integrity Management Plan in 2002 that detailed our plans for testing and assessing each segment of the pipeline. The IMP regulations require that the baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. We expect to spend $0.6 million in 2004 and $0.2 million in 2005 for pipeline integrity testing that will be charged to pipeline operating expense as incurred. As testing is completed, we are required to take prompt remedial action to address integrity issues raised by the assessment. The rehabilitation action required as a result of the assessment and testing is expected to impact our capital expenditure program by requiring us to make improvements to our pipeline. This creates a difficult budgeting and planning challenge as we cannot predict the results of pipeline testing until they are completed. Based on estimated improvements required from assessments made during 2002 and 2003, we have estimated capital expenditures to be made during the IMP assessment period from 2004 through 2009. These capital expenditure projections are based on very preliminary data regarding the cost of rehabilitation. Such capital expenditure projections have been updated to eliminate the segments of the Texas system that were sold or abandoned in 2003, and the projections will be updated as improved data is obtained. During 2003 and 2002, $1.0 million and $1.7 million in capital expenditures were spent for rehabilitation of the Mississippi and Texas Pipeline Systems. Based on actual experience during 2003 and 2002 applied to our written IMP plan, we expect to spend $0.2 million, $1.2 million and $0.7 million in 2004, 2005 and 2006, respectively, for pipeline rehabilitation on the Mississippi System as a result of IMP testing. We currently do not expect to incur any rehabilitation expenditures on the other systems during this period. Expenditures on capital assets to grow the partnership will depend on our access to debt and capital discussed below in "Sources of Future Capital." Our focus will be on acquisitions that add stable cash flows to smooth out the volatility of the crude oil gathering business. Those acquisitions may include the acquisition of additional CO2 assets from Denbury and the construction of CO2 and crude oil pipelines to access Denbury's crude oil fields in Mississippi. Denbury owns additional CO2 industrial sales contracts that we might be able to purchase along with additional volume under our production payment. We may also construct and operate CO2 pipelines next to crude oil pipelines to supply Denbury's fields with the CO2 for tertiary recovery and then to move the resulting crude oil production to market. We will also look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. Capital Resources In March 2003, we entered into a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. The key terms of the Fleet Facility are as follows: - Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%. - The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%. 33 - We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%. - The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. - Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets. - The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders. We were in compliance with the Fleet Facility covenants at December 31, 2003. Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under "Distributions". At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. Outstanding letters of credit issued to Denbury for the purchase of crude oil at December 31, 2003, totaled $12.5 million, and are included in the $21.6 million total above. In February 2004, Denbury agreed to reduce by half its requirement to provide Denbury with letters of credit for our crude oil purchases from them. Sources of Future Capital Prior to 2003, we funded our capital commitments from operating cash and borrowings under bank facilities. In 2003, we issued common units to our general partner for cash and sold assets to fund growth. Our plans for the future include a combination of borrowings and the issuance of additional common units to the public. We have entered into discussions with Fleet National Bank regarding an expansion of our existing credit facility from $65 million to $100 million. We would like to reduce the amount of the facility committed to letters of credit and working capital borrowings from $65 million to $50 million and have $50 million available for acquisitions. We are in discussions with Fleet to determine the terms of the expanded facility. We may consider raising capital through an equity offering of additional common units if we make acquisitions using an expanded credit facility. Any such proceeds could be used to reduce the outstanding balances under the credit facility thereby freeing up debt capacity to use for additional accretive acquisitions. An equity offering would probably not occur before the fourth quarter of 2004. Distributions As a master limited partnership, the key consideration of our Unitholders is the amount of our distribution, its reliability and the prospects for distribution growth. Normally we distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 in total), which was paid in February 2004. 34 Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the distribution measured once each month in order for us to make a distribution for the quarter. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003. The likelihood and timing of the payment of any incentive distributions will depend on our ability to make accretive acquisitions and generate cash flows from of those acquisitions. We do not expect to make incentive distributions during 2004. We believe we will be able to sustain a regular quarterly distribution at $0.15 per unit during 2004. We do not expect to be able to restore the distribution to the targeted minimum quarterly distribution level of $0.20 per unit until 2005. However, if we exceed our expectations for improving the performance of the business, if our capital projects cost less than we currently estimate, or if our access to capital allows us to make accretive acquisitions, we may be able to restore the targeted minimum quarterly distribution sooner. Available Cash before reserves for the year ended December 31, 2003, is as follows (in thousands): Net income................................................... $ 13,322 Depreciation and amortization................................ 6,504 Excluded gain from asset sales............................... (13,088) Cash proceeds in excess of gains on certain asset sales...... 879 Non-cash charges............................................. 229 Maintenance capital expenditures............................. (4,176) ----------- Available Cash before reserves............................... $ 3,670 ===========
Available Cash (a non-GAAP liquidity measure) has been reconciled to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003 below. The non-GAAP financial measure of Available Cash is calculated in accordance with generally accepted accounting principles (GAAP), with the exception of maintenance capital expenditures as used in our calculation of Available Cash. Maintenance capital expenditures are capital expenditures (as defined by GAAP) to replace or enhance partially or fully depreciated assets in order to sustain the existing operating capacity or efficiency of our assets and extend their useful lives. We believe that investors benefit from having access to the same financial measures being utilized by management. Available Cash is a liquidity measure used by our management to compare cash flows generated by the Partnership to the cash distribution we pay to our limited partners and the general partner. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure tells investors whether or not the Partnership is generating cash flows at a level that can support a quarterly cash distribution to our partners. Lastly, Available Cash (also referred to as distributable cash flow) is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships. Several adjustments to net income are required to calculate Available Cash. These adjustments include: (1) the addition of non-cash expenses such as depreciation and amortization expense; (2) miscellaneous non-cash adjustments such as the addition of decreases or the subtraction of increases in the value of financial instruments; and (3) the subtraction of maintenance capital expenditures. See "Distributions" above. The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003, is as follows (in thousands): 35
Year Ended December 31, 2003 ------------ Cash flows from operating activities................................. $ 4,693 Adjustments to reconcile operating cash flows to Available Cash: Maintenance capital expenditures................................. (4,176) Proceeds from sales of certain assets............................ 1,055 Change in fair value of derivatives.............................. (39) Amortization of credit facility issuance fees.................... (1,031) Net effect of changes in operating accounts not included in calculation of Available Cash..................... 3,168 --------- Available Cash before reserves....................................... $ 3,670 =========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS Contractual Obligation and Commercial Commitments In addition to the Fleet Facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes our obligations and commitments at December 31, 2003 (in thousands).
Payments Due by Period ----------------------------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations 1 Year Years Years Years Total -------- -------- -------- -------- -------- Long-term Debt ..................... $ -- $ 7,000 $ -- $ -- $ 7,000 Operating Leases ................... 3,048 3,539 1,074 935 8,596 Pennzoil litigation settlement ...................... 12,750 -- -- -- 12,750 Mississippi oil spill fine ......... 3,000 -- -- -- 3,000 Offshore pipeline removal ......................... 700 -- -- -- 700 Unconditional Purchase Obligations ..................... 89,436 -- -- -- 89,436 -------- -------- -------- -------- -------- Total Contractual Cash Obligations ..................... $108,934 $ 10,539 $ 1,074 $ 935 $121,482 ======== ======== ======== ======== ========
In December 2003, our insurers settled litigation with Pennzoil-Quaker State for $12.8 million. (see Note 18 to the consolidated financial statements.) We have recorded in accrued liabilities on our consolidated statement of operations the obligation for this settlement, and we have recorded the insurance reimbursement for this obligation in insurance receivable. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and with our funding the remaining $6.9 million. We expect to receive reimbursement from the insurance company no later than May 2004. We expect to pay the estimated $3.0 million fine related to the Mississippi oil spill that occurred in 1999 (see Note 18 to the consolidated financial statements) during the second quarter of 2004. We expect to incur approximately $0.7 million to remove an abandoned offshore pipeline during the second quarter of 2004. While the temporary funding of the litigation settlement and the payment of the fine and pipeline removal costs will increase our average outstanding debt during 2004, we believe we have sufficient capacity under the Fleet Facility to meet these obligations. Off-Balance sheet Arrangements We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed in this section, nor do we have any debt or equity triggers based upon our unit or commodity prices. 36 OTHER MATTERS Risk Factors Related to Our Business The success of our crude oil gathering, marketing and pipeline operations is dependent upon increases in the availability of crude oil supplies and our ability to secure those supplies. Securing additional supplies of crude oil from increased production by oil companies and by aggressive lease gathering efforts depends partially on the ability of oil producers to increase production. Factors affecting an increase in production can include the prevailing market price for oil, the exploration and production budgets of the major and independent oil companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters that are beyond our control. The profitability of our crude oil gathering and marketing operations depends primarily on the volumes of crude oil we purchase and gather. Natural declines in crude oil production from depleting wells or volumes lost to competitors must be replaced by contracts for new supplies of crude oil so as to maintain the volumes of crude oil we purchase. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil. Our operations are dependent upon demand for crude oil by refiners in the Gulf Coast and Midwest. Any decrease in this demand could adversely affect our business. This demand is dependent on the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. We face intense competition in our crude oil gathering and marketing activities. Our competitors include independent gatherers, the major integrated oil companies and their marketing affiliates and other marketers of various sizes, financial resources and experience. Many of these competitors have capital resources many times greater than ours and control much greater supplies of crude oil. We are exposed to the credit risk of our customers in the ordinary course of our crude oil gathering and marketing operations. There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counter-parties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us. In those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for the distribution of proceeds to all parties. In other cases, we pay all or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties. The profitability of our crude oil pipeline operations depends on the volume of crude oil shipped by third parties and on our interconnections with other crude oil pipelines. Third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. Additionally, in Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our profitability. Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines can result in less demand for our transmission services. Our operations are subject to federal and state environmental and safety regulations and laws related to environmental protection and operational safety. Our crude oil gathering and pipeline operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or 37 claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through greater margins, higher tariffs or insurance reimbursements; our cash flows and results of operations could be materially impacted. The transportation and storage of crude oil results in a risk that crude oil and related hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. Certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes gathered by truck or transmitted by our pipelines. As a result, we may experience declines in segment margin and profitability should our volumes decrease. Our CO2 operations are exposed to risks related to Denbury's operation of their CO2 fields, equipment and pipeline. Because Denbury produces the CO2 and transports the CO2 to our customers, any long-term failure of their operations could have an impact on our ability to meet our obligations to our CO2 customers. We have no other supply of CO2 or method to transport it to our customers. Fluctuations in demand for CO2 by our industrial customers could materially impact our profitability. Our customers are not contractually obligated to purchase volumes in excess of the take-or-pay amounts in the contracts. The customers have processing facilities located at the delivery points on Denbury's pipeline. Fluctuations in their demand due to market forces or operational problems could result in a reduction in our revenues from the sales of CO2. The CO2 supplied by Denbury to us for our sale to our customers could fail to meet the quality standards in the contracts due to impurities or water vapor content. If the CO2 were below specifications, we could be contractually obligated to provide compensation to our customers for the costs incurred in raising the CO2 quality to serviceable levels. Our wholesale CO2 industrial marketing operations are dependent on three customers. Should one or more of those customers experience financial difficulties such that they fail to purchase their required minimum take-or-pay volume and fail to compensate us for the lost revenue, our profitability could be materially impacted. The three customers appear to be credit worthy, however there can be no assurance that an unanticipated deterioration in their ability to meet their obligations to us might not occur. Newly acquired properties could expose us to environmental liabilities and increased regulatory compliance costs. Our business plan includes making acquisitions to increase our cash flows. Assets that we may acquire will likely have associated environmental liabilities, as well as required compliance with regulations such as the integrity management program for regulated pipelines. Although we will attempt to identify such exposures and address the associated costs through indemnities, purchase price adjustments or insurance, we may incur costs not covered by indemnity, insurance or reserves. Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of reserves. Because distributions to our unitholders are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made in periods when we record losses and might not be made during periods when we record profits. The terms of our credit facility may limit our ability to borrow additional funds, make distributions to unitholders, or capitalize on business opportunities. Our credit facility includes limitations on our ability to make distributions to our unitholders and require approval of lenders to take certain actions. Any refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it could substantially reduce distributions to our unitholders and might reduce 38 our ability to grow the business. The after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal and state income tax purposes. If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Some or all of the distributions made to unitholders would be treated as dividend income, and no income, gains, losses or deductions would flow through to unitholders. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the unitholders. We believe a substantial number of our Common Units are held by entities that derive a tax benefit from investment in partnership-type entities with large gross receipts. Should a change occur such that our revenues declined to a level that these investors might find alternative sources for this tax benefit other than by ownership in our Common Units, an adverse change in our unit price could take place. This condition could occur at the same time that we would be growing our distribution or otherwise increasing the value of our Common Units to the general investing public. Crude Oil Contamination We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurers settled this litigation for $12.8 million. We have recorded in accrued liabilities on our consolidated balance sheet the obligation for this settlement, and, in insurance receivable, we have recorded the insurance reimbursement for this obligation. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million funded by us. We expect to receive reimbursement from the insurance company no later than May 2004 for the portion funded by us. The settlement of this litigation had no effect on our results of operations. PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter. Insurance We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance policies are subject to deductibles that we consider reasonable. The policies do not cover every potential risk associated with operating our assets, including the potential for a loss of significant revenues. Consistent with the coverage available in the industry, our policies provide limited pollution coverage, with broader coverage for sudden and accidental pollution events. Additionally, as a result of the events of September 11, the cost of insurance available to the industry has risen significantly, and insurers have excluded or reduced coverage for losses due to acts of terrorism and sabotage. Since September 11, 2001, warnings have been issued by various agencies of the United States Government to advise owners and operators of energy assets that those assets may be a future target of terrorist organizations. Any future terrorist attacks on our assets, or assets of our customers or competitors could have a material adverse effect on our business. We believe that we are adequately insured for public liability and property damage to others as a result of our operations. However, no assurances can be given that an event not fully insured or indemnified against will not materially and adversely affect our operations and financial condition. Additionally, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. NEW ACCOUNTING PRONOUNCEMENTS SFAS 143 In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement 39 obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard was effective for us on January 1, 2003. With respect to our pipelines, federal regulations require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon expiration of the lease term. For our pipelines, we are unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations would be settled. For the truck unload stations, the site leases have provisions such that the lease continues until one of the parties gives notice that it wishes to end the lease. At this time we cannot reasonably estimate when such notice would be given and when the obligations to remove our improvements would be settled. We will record asset retirement obligations in the period in which we determine the settlement dates. In the third quarter of 2003, we recorded an obligation to remove a pipeline from offshore waters as a result of this standard. This pipeline has been out of service since 1998. The State of Louisiana advised us that the pipeline should be removed. We expect to remove this pipeline during 2004. SFAS 145 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions related to the rescission of SFAS No. 4 were applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 were effective for transactions occurring after May 15, 2002. All other provisions were effective for financial statements issued on or after May 15, 2002, with early application encouraged. The adoption of this statement did not have a material effect on our results of operations. SFAS 146 On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the date of commitment to an exit plan. This adoption of this statement on January 1, 2003, had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 to the consolidated financial statements. Interpretation No. 45 We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18 to the consolidated financial statements. 40 Interpretation No 46 In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements. SFAS 148 We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements. SFAS 149 On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. SFAS 150 In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our primary price risk relates to the effect of crude oil price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. We utilize NYMEX commodity based futures contracts and forward contracts to hedge our exposure to these market price fluctuations as needed. At December 31, 2003, we had no contracts outstanding. At December 31, 2003, we held 49,000 barrels of crude oil in inventory with a carrying cost of $1.5 million. The market value of this inventory at December 31, 2003 was $30,000 greater than its cost. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Consolidated Financial Statements" on page 52. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. ITEM 9A. CONTROLS AND PROCEDURES We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K and have determined that such disclosure 41 controls and procedures are adequate and effective in all material respects in providing to them on a timely basis material information relating to us (including our consolidated subsidiaries) required to be disclosed in this annual report. There have been no significant changes in our internal controls over financial reporting during the three months ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT We do not directly employ any persons responsible for managing or operating the Partnership or for providing services relating to day-to-day business affairs. The General Partner provides such services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. The Board of Directors of the General Partner (the "Board") consists of eight persons. Four of the directors, including the Chairman of the Board, are executives of Denbury. Our Chief Executive Officer serves on the Board. The three remaining directors are independent of Genesis and Denbury or any of its affiliates. Directors and Executive Officers of the General Partner Set forth below is certain information concerning the directors and executive officers of the General Partner. All executive officers serve at the discretion of the General Partner.
Name Age Position ---- --- -------- Gareth Roberts................ 51 Director and Chairman of the Board Mark J. Gorman................ 49 Director, Chief Executive Officer and President Ronald T. Evans............... 41 Director Herbert I. Goodman............ 81 Director Susan O. Rheney............... 44 Director Phil Rykhoek.................. 47 Director J. Conley Stone............... 72 Director Mark A. Worthey............... 46 Director Ross A. Benavides............. 50 Chief Financial Officer, General Counsel and Secretary Kerry W. Mazoch............... 57 Vice President, Crude Oil Acquisitions Karen N. Pape................. 46 Vice President and Controller
Gareth Roberts has served as a Director and Chairman of the Board of the General Partner since May 2002. Mr. Roberts is President, Chief Executive Officer and a director of Denbury Resources Inc. and has served in those capacities since 1992. Mr. Roberts also serves on the board of directors of Belden & Blake Corporation. Mark J. Gorman has served as a Director of the General Partner since December 1996 and as President and Chief Executive Officer since October 1999. From December 1996 to October 1999 he served as Executive Vice President and as Chief Operating Officer from October 1997 to October 1999. He was President of Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from September 1992 to December 1996. Ronald T. Evans has served as a director of the General Partner since May 2002. Mr. Evans is Senior Vice President of Reservoir Engineering of Denbury and has served in that capacity since September 1999. Before joining Denbury, Mr. Evans was employed as Engineering Manager with Matador Petroleum Corporation for three years and employed by Enserch Exploration, Inc. for twelve years in various positions. Herbert I. Goodman has served as a director of the General Partner since January 1997. He is the Chairman of IQ Holdings, Inc., a manufacturer and marketer of petrochemical-based consumer products. During 2001, he served as the Chief Executive Officer of PEPEX.NET, LLC, which provides electronic trading solutions to the international oil industry. Since 2002 he has served as Chairman of PEPEX.NET, LLC. From 1988 until 1996 he was Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading and consulting business. 42 Susan O. Rheney became a Director of the General Partner in March 2002. Ms. Rheney is a private investor and formerly was a principal of The Sterling Group, L.P., a private financial and investment organization, from 1992 to 2000. Ms. Rheney is a director of Texas Petrochemical Holdings, Inc., a chemical manufacturer, where she serves on the audit and finance committees. She is also a director of Mail-Well, Inc., a supplier of printing services and products, where she serves on the audit and governance and nominating committees. Phil Rykhoek has served as a director of the General Partner since May 2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President, Secretary and Treasurer of Denbury, and has served in those capacities since 1995. J. Conley Stone has served as a director of the General Partner since January 1997. From 1987 to his retirement in 1995, he served as President, Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe Line Company, a common carrier liquid petroleum products pipeline transporter. Mark A. Worthey has served as a director of the General Partner since May 2002. Mr. Worthey is Senior Vice President, Operations for Denbury and has been with Denbury since September 1992. Ross A. Benavides has served as Chief Financial Officer of the General Partner since October 1998. He has served as General Counsel and Secretary since December 1999. Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of the General Partner since August 1997. From 1991 to 1997 he held the position of Vice President and General Manager of Crude Oil Acquisitions at Northridge Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines Limited. Karen N. Pape was named Vice President and Controller of the General Partner effective in March 2002. Ms. Pape has served as Controller and as Director of Finance and Administration of the General Partner since December 1996. From 1990 to 1996, she was Vice President and Controller of Howell Corporation. Board Committees The Audit Committee consists of Susan O. Rheney, Herbert I. Goodman and J. Conley Stone. The Audit Committee has been established in accordance with SEC rules and regulations, and all members are independent directors as defined under the rules of the American Stock Exchange. The Board of Directors believes that Susan O. Rheney qualifies as an audit committee financial expert as such term is used in the rules and regulations of the SEC. The committee engages our independent auditors and oversees our independence from the auditors, pre-approves any services provided by our independent auditors, oversees the quality and integrity of our financial reports and our systems of internal controls with respect to finance, accounting, legal compliance and ethics, and oversees our anonymous complaint procedure established for our employees. The Audit Committee adopted a written Audit Committee charter on August 7, 2003. The full text of the Audit Committee charter is available on our website. Additionally, the General Partner is authorized to seek special approval from the Audit Committee of any resolution of a potential conflict of interest between the General Partner or of any of its affiliates and the Partnership or any of its affiliates. The Board has established a compensation committee to oversee compensation decisions for the employees of the General Partner, as well as the compensation plans of the General Partner. The members of the Compensation Committee are Gareth Roberts, Susan O. Rheney and Herbert I. Goodman, all of whom are non-employee directors of the General Partner. Code of Ethics We have adopted a code of ethics that is applicable to, among others, the principal financial officer and the principal accounting officer. The Genesis Energy Financial Employee Code of Professional Conduct is posted at our website, where we intend to report any changes or waivers. Section 16(a) Compliance Section 16(a) of the Securities Exchange Act of 1934 requires the officers and directors of the General Partner and persons who own more than ten percent of a registered class of the equity securities of the Partnership to file reports of ownership and changes in ownership with the SEC and the American Stock Exchange. Based solely on its review of the copies of such reports received by it, or written representations from certain reporting persons that 43 no Forms 5 was required for those persons, we believe that during 2003 its officers and directors complied with all applicable filing requirements in a timely manner. ITEM 11. EXECUTIVE COMPENSATION EXECUTIVE OFFICER COMPENSATION Under the terms of the Partnership Agreement, we are required to reimburse the General Partner for expenses relating to the operation of the Partnership, including salaries and bonuses of employees employed on behalf of the Partnership, as well as the costs of providing benefits to such persons under employee benefit plans and for the costs of health and life insurance. See "Certain Relationships and Related Transactions." Summary Compensation Table The following table summarizes certain information regarding the compensation paid or accrued by Genesis during 2003, 2002, and 2001 to the Chief Executive Officer and each of our three other executive officers (the "Named Officers").
Long-Term Compensation Annual Compensation Awards -------------------------------------- --------------- Securities Other Annual underlying All Other Salary Bonus Compensation SARs Granted(2) Compensation Name and Principal Position Year $ $ $(1) # $ - --------------------------- ---- ------- ----- ------------ --------------- ------------ Mark J. Gorman 2003 275,000 4,070 12,755 23,620 15,000(3) Chief Executive Officer 2002 270,000 5,193 -- -- 11,500(4) and President 2001 270,000 56,814 -- -- 10,200(5) Ross A. Benavides 2003 185,000 2,738 8,580 15,889 13,803(6) Chief Financial Officer, 2002 180,000 3,462 -- -- 11,500(4) General Counsel and 2001 175,000 54,785 -- -- 10,200(5) Secretary Kerry W. Mazoch 2003 175,000 2,590 8,116 15,030 13,023(7) Vice President, Crude 2002 170,000 3,270 -- -- 11,478(8) Oil Acquisitions 2001 169,000 30,720 -- -- 10,200(5) Karen N. Pape 2003 141,000 2,094 6,563 12,153 10,533(9) Vice President and 2002 136,000 2,616 -- -- 10,118(10) Controller
(1) Represents the value deemed to have been "earned" during the year under the Stock Appreciation Rights Plan discussed below. No Named Officer had other "Perquisites and Other Personal Benefits" with a value greater than the lesser of $50,000 or 10% of reported salary and bonus. (2) SARs are Stock Appreciation Rights. See additional information in the table below. (3) Includes $9,000 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan. (4) Includes $5,500 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan. (5) Includes $5,100 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. (6) Includes $8,282 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan. (7) Includes $7,802 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan 44 (8) Includes $5,500 of Company-matching contributions to a defined contribution plan and $5,978 of profit-sharing contributions to a defined contribution plan. (9) Includes $6,320 of Company matching contributions to a defined contribution plan and $4,213 of profit-sharing contributions to a defined contribution plan. (10) Includes $5,059 of Company-matching contributions to a defined contribution plan and $5,059 of profit-sharing contributions to a defined contribution plan. Stock Appreciation Rights Plan In December 2003, the Board approved a Stock Appreciation Rights plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit. The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below. Upon vesting, the participant may exercise his rights to receive a cash payment equal to the difference between the average of the closing market price of Genesis Energy, L.P. Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date. Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested. On December 31, 2003, the initial award of rights was made to employees and directors. The following tables show the stock appreciation rights granted to the Executive Officers and the values of the stock appreciation rights at December 31, 2003. Information on rights granted to non-employee directors is included in the section entitled Director Compensation. SAR Grants During the Year Ended December 31, 2003
Individual Grants - -------------------------------------------------------------------------------------------- Potential realizable value at Number of Percent Grant assumed annual rates of Securities of total date stock price appreciation underlying SARs granted Exercise closing for SAR term SARs to employees price price Expiration ----------------------------- Name granted (#) in fiscal year $/Unit $/Unit date 5%($) 10%($) - ----------------- ----------- -------------- -------- ------- ---------- ------- ------- Mark J. Gorman 23,620 5.8% 9.26 9.80 12/31/2013 137,553 348,585 Ross A. Benavides 15,889 3.9% 9.26 9.80 12/31/2013 92,531 234,491 Kerry W. Mazoch 15,030 3.7% 9.26 9.80 12/31/2013 87,528 221,814 Karen N. Pape 12,153 3.0% 9.26 9.80 12/31/2013 70,774 179,355
December 31, 2003 SAR Values 45
Number of Common Units Value of underlying unexercised unexercised in-the-money SARs at December 31, 2003 (#) SARs at December 31, 2003 ($) ----------------------------- ----------------------------- Name Exercisable Unexercisable Exercisable Unexercisable - ------------------ ----------- ------------- ----------- ------------- Mark J. Gorman -- 23,620 -- 12,755 Ross A. Benavides -- 15,889 -- 8,580 Kerry W. Mazoch -- 15,030 -- 8,116 Karen N. Pape -- 12,153 -- 6,563
Bonus Plan In May 2003, the Compensation Committee of the Board of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the financial performance of the Partnership by rewarding employees for achieving financial performance objectives. The Bonus Plan is administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a maximum bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash. Bonuses will be paid to employees after the end of the year. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and the General Partner can amend or change the Bonus Plan at any time. DIRECTOR COMPENSATION Information regarding the compensation received from the General Partner by Mr. Gorman, President, Chief Executive Officer and a director of the General Partner, is disclosed under the heading "Executive Officer Compensation". Directors Fees The three independent directors receive an annual fee of $30,000. The Audit Committee Chairman receives an additional annual fee of $4,000 and all members of the Audit Committee receive $1,500 for attendance at each committee meeting. Denbury receives $120,000 from the Partnership for providing four of its executives as directors. Mr. Gorman does not receive a fee for serving as a director. Stock Appreciation Rights The non-employee directors received stock appreciation rights under the same terms as the Executive Officers. Grants issued to directors during 2003 were:
Number of Securities underlying Exercise SARs price Expiration Name granted (#) $/Unit date - -------------------- ----------- --------- ---------- Gareth Roberts 2,576 9.26 12/31/2013 Ronald T. Evans 2,576 9.26 12/31/2013 Herbert I. Goodman 3,092 9.26 12/31/2013 Susan O. Rheney 3,435 9.26 12/31/2013 J. Conley Stone 3,092 9.26 12/31/2013 Mark A. Worthey 2,576 9.26 12/31/2013
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 46 Beneficial Ownership of Partnership Units The following table sets forth certain information as of February 28, 2004, regarding the beneficial ownership of our units by beneficial owners of 5% or more of the units, by directors and the executive officers of our general partner and by all directors and executive officers as a group. This information is based on data furnished by the persons named.
Beneficial Ownership of Common Units ------------------------------------ Percent Title of Class Name Number of Units of Class -------------------- -------------------- --------------- -------- Genesis Energy, L.P. Genesis Energy, Inc. 688,811 7.4 Common Unit Gareth Roberts 10,000 * Mark J. Gorman 25,525 * Ronald T. Evans 1,000 * Herbert I. Goodman 2,000 * Susan O. Rheney 700 * Phil Rykhoek 4,000 * J. Conley Stone 1,000 * Mark A. Worthey 1,600 * Ross A. Benavides 9,283 * Kerry W. Mazoch 8,669 * Karen N. Pape 3,386 * All directors and executive officers as a group (11 in number) 67,163 *
---------- * Less than 1% Each unitholder in the above table is believed to have sole voting and investment power with respect to the shares beneficially held. Included in the units held by Mark A Worthey are 500 units held for a minor child. Included in the units held by Kerry W. Mazoch are 584 units held with his children. Beneficial Ownership of General Partner Interest Genesis Energy, Inc. owns all of our 2% general partner interest and all of our incentive distribution rights, in addition to 7.4% of our units. Genesis Energy, Inc. is a wholly-owned subsidiary of Denbury Resources, Inc. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Our General Partner Our operations are managed by, and our employees are employed by, Genesis Energy, Inc., our general partner. Our general partner does not receive any management fee or other compensation in connection with the management of our business, but is reimbursed for all direct and indirect expenses incurred on our behalf. During 2003, these reimbursements totaled $16.0 million. At December 31, 2003, we owed the general partner $0.1 million related to these services. Our general partner owns the 2% general partner interest and all incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.3% of amounts we distribute in excess of $0.25 per unit, 23.5% of the amounts we distribute in excess of $0.28 per unit, and 49% of the amounts we distribute in excess of $0.33 per unit. Relationship with Denbury Resources, Inc. Through its control of our general partner, Denbury has the ability to control our management. During 2003, we acquired a CO2 volumetric production payment and related wholesale marketing contracts from Denbury for $24.4 million. Additionally we enter into transactions with Denbury in the ordinary course of its operations. During 2003, these transactions included: 47 - Purchases of crude oil from Denbury totaling $59.7 million. We provide letter of credit to Denbury related to these purchases. - Provision of CO2 transportation services to our wholesale industrial customers by Denbury's pipeline. The fees for this service totaled $0.4 million in 2003. - Provision of services by Denbury officers as directors of our general partner. We paid Denbury $120,000 for these services in 2003. At December 31, 2003, we owed Denbury $6.9 million for purchases of crude oil and $0.1 million for transportation services. In 2002, we amended our partnership agreement to broaden the right of the Common Unitholders to remove the General Partner. Prior to this amendment, the general partner could only be removed for cause and with approval by holders of two-thirds or more of the outstanding limited partner interests in GELP. As amended, the partnership agreement provides that, with the approval of at least a majority of the limited partners in GELP, the general partner also may be removed without cause. Any limited partner interests held by the general partner and its affiliates would be excluded from such a vote. The amendment further provides that if it is proposed that the removal is without cause and an affiliate of Denbury is the general partner to be removed and not proposed as a successor, then any action for removal must also provide for Denbury to be granted an option effective upon its removal to purchase GELP's Mississippi pipeline system at a price that is 110 percent of its fair market value at that time. Fair value is to be determined by agreement of two independent appraisers, one chosen by the successor general partner and the other by Denbury or if they are unable to agree, the mid-point of the values determined by them. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following table summarizes the aggregate fees billed to us by Deloitte & Touche LLP.
2003 2002 ---- ---- (in thousands) Audit Fees (a)....................................... $ 211 $ 140 Audit-Related Fees (b)............................... 92 71 --------- --------- Total................................................ $ 303 $ 211 ========= =========
(a) Fees for audit services billed in 2003 consisted of: Audit of our annual financial statements Audit of our General Partner financial statements Reviews of our quarterly financial statements Financial statement audits of prior years that were originally audited by Arthur Andersen LLP. Fees for audit services billed in 2002 consisted of: Audit of our annual financial statements Reviews of our quarterly financial statements. (b) Fees for audit-related services in 2003 and 2002 consisted of: Financial accounting and reporting consultations Sarbanes-Oxley Act, Section 404 advisory services Employee benefit plan audits. Deloitte provided no tax services or other services to us in 2002 or 2003. In considering the nature of the services provided by Deloitte, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with Deloitte and management of our General Partner to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants. 48 Pre-Approval Policy The services by Deloitte in 2003 were pre-approved in accordance with the pre-approval policy and procedures adopted by the Audit Committee at its May 9, 2003 meeting. This policy describes the permitted audit, audit-related, tax and other services (collectively, the "Disclosure Categories") that the independent auditor may perform. The policy requires that prior to the beginning of each fiscal year, a description of the services (the "Service List") expected to be performed by the independent auditor in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval. Services provided by the independent auditor during the following year that are included in the Service List were pre-approved following the policies and procedures of the Audit Committee. Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meeting. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Consolidated Financial Statements" set forth on page 52. (a)(3) Exhibits 3.1 Certificate of Limited Partnership of Genesis Energy, L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545) 3.2 Third Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31, 2002) 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996) 3.4 Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.1 to Form 8-K dated July 31, 2002) 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"), Howell Corporation ("Howell"), certain subsidiaries of Howell, Genesis, the Operating Partnership and Genesis Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for the year ended December 31, 1996) 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended December 31, 1996) 10.3 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) 10.4 Credit Agreement dated as of March 14, 2003, between Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet National Bank and Certain Financial Institutions (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2002) 10.5 Pipeline Sale and Purchase Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and Genesis Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K dated October 31, 2003) 10.6 Purchase and Sale Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K dated October 31, 2003) *10.7 Production Payment Purchase and Sale Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. executed November 14, 2003
49 *10.8 Carbon Dioxide Transportation Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. *10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan. 11.1 Statement Regarding Computation of Per Share Earnings (See Notes 2 and 7 to the Consolidated Financial Statements) *21.1 Subsidiaries of the Registrant *31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification by Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
---------- * Filed herewith + A management contract or compensation plan or arrangement. (b) Reports on Form 8-K A Current Report on Form 8-K was filed on November 24, 2003, in connection with the purchase of a volumetric production payment from Denbury. A Current Report on Form 8-K was furnished on November 11, 2003, providing, under Items 7, 9 and 12, the Partnership's news release including attached schedules dated November 11, 2003, that announced the Partnership's financial and operating results for the three and nine month periods ended September 30, 2003. A Current Report on Form 8-K was filed on November 4, 2003, including, as an exhibit, pro forma financial statements, in connection with the sale of parts of the Partnership's crude oil pipeline and associated gathering and marketing operations. A Current Report on Form 8-K was furnished October 15, 2003, providing, under Items 7, 9 and 12, the Partnership's news release that announced the signing of a purchase and sale agreement to sell parts of the Partnership's crude oil pipeline and associated gathering and marketing operations and the signing of a non-binding letter of intent to purchase a volumetric production payment from Denbury. 50 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on the 29th day of March, 2004. GENESIS ENERGY, L.P. (A Delaware Limited Partnership) By: GENESIS ENERGY, INC., as General Partner By: /s/ Mark J. Gorman ------------------------------------- Mark J. Gorman Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. /s/ MARK J. GORMAN Director, Chief Executive Officer March 29, 2004 - ---------------------------- and President Mark J. Gorman (Principal Executive Officer) /s/ ROSS A. BENAVIDES Chief Financial Officer, March 29, 2004 - ---------------------------- General Counsel and Secretary Ross A. Benavides (Principal Financial Officer) /s/ KAREN N. PAPE Vice President and Controller March 29, 2004 - ---------------------------- (Principal Accounting Officer) Karen N. Pape Chairman of the Board and March __, 2004 - ---------------------------- Director Gareth Roberts /s/ RONALD T. EVANS Director March 29, 2004 - ---------------------------- Ronald T. Evans /s/ HERBERT I GOODMAN Director March 29, 2004 - ---------------------------- Herbert I. Goodman /s/ SUSAN O. RHENEY Director March 29, 2004 - ---------------------------- Susan O. Rheney /s/ PHIL RYKHOEK Director March 29, 2004 - ---------------------------- Phil Rykhoek /s/ J. CONLEY STONE Director March 29, 2004 - ---------------------------- J. Conley Stone /s/ MARK A. WORTHEY Director March 29, 2004 - ---------------------------- Mark A. Worthey
51 GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Independent Auditors' Report .............................................. 53 Consolidated Balance Sheets, December 31, 2003 and 2002 ................... 54 Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 55 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 56 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 57 Consolidated Statements of Partners' Capital for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 58 Notes to Consolidated Financial Statements ................................ 59
52 INDEPENDENT AUDITORS' REPORT Genesis Energy, L.P. Houston, Texas We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P., (the "Partnership") as of December 31, 2003 and 2002, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 2 and 4 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill and discontinued operations. As discussed in Note 17 to the consolidated financial statements, in 2001, the Partnership changed its method of accounting for derivative financial instruments. /s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Houston, Texas March 19, 2004 53 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands)
December 31, December 31, 2003 2002 ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents ................................... $ 2,869 $ 1,071 Accounts receivable - trade ................................. 66,732 80,664 Inventories ................................................. 1,546 4,952 Insurance receivable ........................................ 15,524 3,425 Other ....................................................... 1,540 1,985 --------- --------- Total current assets ..................................... 88,211 92,830 FIXED ASSETS, at cost .......................................... 70,695 118,418 Less: Accumulated depreciation ............................. (36,724) (73,958) --------- --------- Net fixed assets ......................................... 33,971 44,460 CO2 ASSETS, net of amortization ................................ 24,073 -- OTHER ASSETS, net of amortization .............................. 860 980 --------- --------- TOTAL ASSETS ................................................... $ 147,115 $ 137,537 ========= ========= LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable - Trade .................................................... $ 60,108 $ 82,640 Related party ............................................ 7,067 4,746 Accrued liabilities ......................................... 20,069 8,834 --------- --------- Total current liabilities ................................ 87,244 96,220 LONG-TERM DEBT ................................................. 7,000 5,500 COMMITMENTS AND CONTINGENCIES (Note 18) MINORITY INTERESTS ............................................. 517 515 PARTNERS' CAPITAL Common unitholders, 9,314 and 8,625 units issued and outstanding, respectively .................................. 51,299 34,626 General partner ............................................. 1,055 715 Accumulated other comprehensive loss ........................ -- (39) --------- --------- Total partners' capital .................................. 52,354 35,302 --------- --------- TOTAL LIABILITIES AND PARTNERS' CAPITAL ........................ $ 147,115 $ 137,537 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 54 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts)
Year Ended December 31, --------------------------------------------- 2003 2002 2001 ----------- ----------- ----------- REVENUES: Crude oil gathering and marketing: Unrelated parties .......................................... $ 641,684 $ 636,107 $ 2,971,785 Related parties ............................................ -- 3,036 29,847 Crude oil pipeline ............................................ 15,134 13,485 9,948 CO2 revenues .................................................. 1,079 -- -- ----------- ----------- ----------- Total revenues .......................................... 657,897 652,628 3,011,580 COSTS AND EXPENSES: Crude oil costs: Unrelated parties .......................................... 562,626 589,598 2,943,935 Related parties ............................................ 59,653 26,452 36,699 Field operating ............................................ 11,497 11,916 11,270 Crude oil pipeline operating costs ............................ 10,026 8,076 7,038 CO2 transportation costs - related party ...................... 355 -- -- General and administrative .................................... 8,768 7,864 11,307 Depreciation and amortization ................................. 4,641 4,603 5,340 Impairment of long-lived assets ............................... -- -- 9,589 Change in fair value of derivatives ........................... -- 1,279 (1,681) Net gain on disposal of surplus assets ........................ (236) (705) (167) Other operating charges ....................................... -- 1,500 1,500 ----------- ----------- ----------- Total costs and expenses ................................ 657,330 650,583 3,024,830 ----------- ----------- ----------- OPERATING INCOME (LOSS) .......................................... 567 2,045 (13,250) OTHER INCOME (EXPENSE): Interest income ............................................... 34 69 166 Interest expense .............................................. (1,020) (1,104) (693) ----------- ----------- ----------- Income (loss) from continuing operations before minority interests and cumulative effect of change in accounting principle ....................................... (419) 1,010 (13,777) Minority interests in continuing operations ...................... -- -- (1) ----------- ----------- ----------- INCOME (LOSS) FROM CONTINUING OPERATIONS ......................... (419) 1,010 (13,776) Discontinued operations: Income from operations from discontinued Texas System (including gain on disposal of $13,028) before minority interests ..................................... 13,742 4,082 (30,306) Minority interests in discontinued operations .................... 1 -- (3) ----------- ----------- ----------- INCOME FROM DISCONTINUED OPERATIONS .............................. 13,741 4,082 (30,303) CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF MINORITY INTEREST EFFECT ...................................... -- -- 467 ----------- ----------- ----------- NET INCOME (LOSS) ................................................ $ 13,322 $ 5,092 $ (43,612) =========== =========== ===========
55 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED (In thousands, except per unit amounts)
Year Ended December 31, -------------------------------------------- 2003 2002 2001 --------- --------- --------- NET INCOME PER COMMON UNIT- BASIC AND DILUTED: Income (loss) from continuing operations before cumulative effect of change in accounting principle ............................ $ (0.05) $ 0.11 $ (1.57) Income from discontinued operations ................ 1.55 0.47 (3.44) Cumulative effect of change in accounting principle ....................................... -- -- 0.05 --------- --------- --------- NET INCOME (LOSS) .................................. $ 1.50 $ 0.58 $ (4.96) ========= ========= ========= Weighted average number of common units outstanding ........................................... 8,715 8,625 8,624 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands)
Year Ended December 31, ----------------------------------------- 2003 2002 2001 -------- -------- -------- NET INCOME (LOSS) ......................................................... $ 13,322 $ 5,092 $(43,612) OTHER COMPREHENSIVE INCOME (LOSS): Change in fair value of derivatives used for hedging purposes ........ 39 (39) -- -------- -------- -------- COMPREHENSIVE INCOME (LOSS) ............................................... $ 13,361 $ 5,053 $(43,612) ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 56 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
Year Ended December 31, --------------------------------------- 2003 2002 2001 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ............................................... $ 13,322 $ 5,092 $ (43,612) Adjustments to reconcile net income to net cash provided by operating activities - Depreciation ................................................. 5,970 4,965 6,228 Amortization of CO2 contracts and covenant not-to-compete .... 534 848 1,318 Amortization and write-off of credit facility issuance costs . 1,031 736 23 Impairment of long-lived assets .............................. -- -- 45,061 Cumulative effect of change in accounting principle .......... -- -- (467) Change in fair value of derivatives .......................... 39 2,055 (2,259) Gain on disposal of assets ................................... (13,264) (708) (167) Minority interests equity in earnings (losses) ............... 1 -- (4) Other non-cash charges ....................................... 228 1,500 1,605 Changes in components of working capital - Accounts receivable ....................................... 13,932 81,134 167,666 Inventories ............................................... 3,758 (1,051) (2,743) Other current assets ...................................... (11,654) 3,909 4,854 Accounts payable .......................................... (20,211) (86,159) (154,117) Accrued liabilities ....................................... 11,007 (4,904) (5,230) --------- --------- --------- Net cash provided by operating activities ......................... 4,693 7,417 18,156 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment ............................. (4,910) (4,211) (1,882) CO2 contracts acquisition ....................................... (24,401) -- -- Change in other assets .......................................... (24) 5 -- Proceeds from disposal of assets ................................ 22,341 2,243 453 --------- --------- --------- Net cash used in investing activities ............................. (6,994) (1,963) (1,429) CASH FLOWS FROM FINANCING ACTIVITIES: Bank borrowings (repayments), net ............................... 1,500 (8,400) (8,100) Credit facility issuance fees ................................... (1,093) -- (1,312) Issuance of limited and general partner interests ............... 5,012 -- -- Minority interests contributions ................................ 1 -- -- Distributions to common unitholders ............................. (1,294) (1,725) (6,898) Distributions to General Partner ................................ (27) (35) (141) Distributions to minority interest owner ........................ -- -- (1) Purchase of treasury units, net ................................. -- -- (6) --------- --------- --------- Net cash provided by (used in) financing activities ............... 4,099 (10,160) (16,458) Net increase (decrease) in cash and cash equivalents .............. 1,798 (4,706) 269 Cash and cash equivalents at beginning of period .................. 1,071 5,777 5,508 --------- --------- --------- Cash and cash equivalents at end of period ........................ $ 2,869 $ 1,071 $ 5,777 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 57 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In thousands)
Partners' Capital ------------------------------------------------------------------------------- Accumulated Number of Other Common Common General Treasury Comprehensive Units Unitholders Partner Units Income Total --------- ----------- ------- -------- ------------- ----- Partners' capital, January 1, 2001 .......... 8,625 $ 80,960 $ 1,661 $ (6) $ -- $ 82,615 Net loss .................................... -- (42,740) (872) -- -- (43,612) Cash distributions .......................... -- (6,898) (141) -- -- (7,039) Purchase of treasury units .................. -- -- -- (6) -- (6) Issuance of treasury units to Restricted Unit Plan participants ........ -- -- -- 12 -- 12 Excess of expense over cost of treasury units issued for Restricted Unit Plan ................................ -- 39 -- -- -- 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2001 ........ 8,625 31,361 648 -- -- 32,009 Net income .................................. -- 4,990 102 -- -- 5,092 Cash distributions .......................... -- (1,725) (35) -- -- (1,760) Change in fair value of derivatives used for hedging purposes ................ -- -- -- -- (39) 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2002 ........ 8,625 34,626 715 -- (39) 35,302 Net income .................................. -- 13,055 267 -- -- 13,322 Cash distributions .......................... -- (1,294) (27) -- -- (1,321) Issuance of units ........................... 689 4,912 100 -- -- 5,012 Change in fair value of derivatives used for hedging purposes ................ -- -- -- -- 39 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2003 ........ 9,313 $ 51,299 $ 1,055 $ -- $ -- $ 52,354 ===== ======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 58 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Organization Genesis Energy, L.P. ("GELP" or the "Partnership") is a publicly traded Delaware limited partnership engaged in gathering, marketing and transportation of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed in December 1996 through an initial public offering of 8.6 million Common Units, representing limited partner interests in GELP of 98%. The General Partner of GELP is Genesis Energy, Inc. (the "General Partner") which owns a 2% general partner interest in GELP. The General Partner is owned by Denbury Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. In November 2003, an additional 0.7 million Common Units were sold to our general partner in a private placement. These Common Units are not registered with the Securities and Exchange Commission. See Note 7. Genesis Crude Oil, L.P. is the operating limited partnership and is owned 99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to as GCOLP. Basis of Presentation The accompanying financial statements and related notes present the consolidated financial position as of December 31, 2003 and 2002 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 2003, 2002 and 2001, and changes in comprehensive income for the years ended December 31, 2003, 2002 and 2001. All significant intercompany transactions have been eliminated. Certain reclassifications were made to prior period amounts to conform to current period presentation. Such reclassifications had no effect on reported net income, total assets, total liabilities or partners' equity. No provision for income taxes related to the operation of GELP is included in the accompanying consolidated financial statements; as such income will be taxable directly to the partners holding partnership interests in the Partnership. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates that we make include: (1) estimated useful lives of assets, which impacts depreciation and amortization, (2) accruals related to revenues and expenses, (3) liability and contingency accruals, (4) estimated fair value of assets and liabilities acquired, and (5) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred. While we believe these estimates reasonable, actual results could differ from these estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Partnership has no requirement for compensating balances or restrictions on cash. 59 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Inventories Crude oil inventories held for sale are valued at the lower of average cost or market. Fuel inventories are carried at the lower of cost or market. Fixed Assets Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 15 years for pipelines and related assets, 3 to 7 years for vehicles and transportation equipment, and 3 to 10 years for buildings, office equipment, furniture and fixtures and other equipment. Long-lived assets are reviewed for impairment. In 2001, we recorded a charge for impairment of our pipeline assets as we did not believe the recorded values of the assets could be recovered through future cash flows. On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." Under SFAS No. 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil volumes are carried at their weighted average cost. We account for asset retirement obligations in accordance with SFAS 143. SFAS 143 requires that the cost for asset retirement obligations be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense systematically as with depreciation. With respect to our pipelines, federal regulations will require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon termination of the lease term, however the lease terms are continuous until a party to the lease gives notice that it wishes the lease to terminate. However the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates. In the third quarter of 2003, we recorded a liability in the amount of $0.7 million representing the anticipated cost to remove a pipeline from offshore waters of the State of Louisiana. The costs are expected to be incurred before June 30, 2004. CO2 and Other Assets Other assets consist primarily of CO2 assets and intangibles. The CO2 assets include a volumetric production payment and long-term contracts to sell the CO2 volume. The contract value is being amortized on a units-of-production method. See Note 5. Intangibles included a covenant not to compete, which was amortized over five years ending during 2003, and credit facility fees which are being amortized over the period the facility is in effect. Minority Interests Minority interests represent a 0.01% general partner interest in GCOLP held by the General Partner. Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are likely to occur and reasonable estimates can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred. 60 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Revenue Recognition Revenues from gathering and marketing of crude oil are recognized when title to the crude oil is transferred to the customer. Revenues from transportation of crude oil by our pipelines are recognized upon delivery of the barrels to the location designated by the shipper. Pipeline loss allowance revenues are recognized to the extent that pipeline loss allowances charged to shippers exceed pipeline measurement losses for the period based upon the fair market value of the crude oil upon which the allowance is based. Revenues from CO2 activities are recorded when title transfers to the customer at the inlet meter of the customer's facility. Cost of Sales Crude oil cost of sales consists of the cost of crude oil and field and pipeline operating expenses. Field and pipeline operating expenses consist primarily of labor costs for drivers and pipeline field personnel, truck rental costs, fuel and maintenance, utilities, insurance and property taxes. Cost of sales for the CO2 activities consists of a transportation fee charged by Denbury (currently $0.16 per Mcf) to transport the CO2 to the customer through Denbury's pipeline. Derivative Instruments and Hedging Activities We minimize our exposure to price risk by limiting our inventory positions, therefore we rarely need to use derivative instruments. In 2003, we used derivative instruments only once. However should we use derivative instruments to hedge exposure to price risk, we would account for those derivative transactions in accordance with Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded on the balance sheet as assets and liabilities based on the derivative's fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, the derivative's gains and losses offset related results on the hedged item in the income statement. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. If a derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements and is accounted for using traditional accrual accounting. Net Income Per Common Unit Basic and diluted net income per Common Unit is calculated on the weighted average number of outstanding Common Units, after exclusion of the 2 percent General Partner interest from net income. The weighted average number of Common Units outstanding was 8,714,845, 8,624,554 and 8,623,741 for the years ended December 31, 2003, 2002 and 2001, respectively. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. See Note 7 for a computation of net income per Common Unit. Recent Accounting Pronouncements We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See Fixed Assets above. The FASB issued SFAS No. 145, "Rescission of FASB Statements 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This statement revised accounting guidance related to the extinguishment of debt and accounting for certain lease transactions. It also amended other accounting literature to clarify its meaning, applicability and to make various technical corrections. Our adoption of this standard effective January 1, 2003 had no impact on our financial statements. On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the 61 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS date of commitment to an exit plan. This adoption of this statement had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 for information regarding this sale. We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements. We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements. On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. 62 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. INVENTORIES Inventories consisted of the following (in thousands).
December 31, ------------------------------ 2003 2002 ------------ ------------ Crude oil inventories, at lower of cost or market................ $ 1,476 $ 4,841 Fuel and supplies inventories, at lower of cost or market........ 70 111 ------------ ------------ Total inventories.......................................... $ 1,546 $ 4,952 ============ ============
4. FIXED ASSETS Fixed assets consisted of the following (in thousands).
December 31, ------------------------------ 2003 2002 ------------ ------------ Land and buildings............................................... $ 1,481 $ 3,492 Pipelines and related assets..................................... 57,429 101,397 Vehicles and transportation equipment............................ 1,510 1,527 Office equipment, furniture and fixtures......................... 3,043 3,138 Other ........................................................... 7,232 8,864 ------------ ------------ 70,695 118,418 Less - Accumulated depreciation.................................. (36,724) (73,958) ------------- ------------ Net fixed assets................................................. $ 33,971 $ 44,460 ============ ============
Depreciation expense, including discontinued operations, was $5,970,000, $4,965,000 and $6,228,000 for the years ended December 31, 2003, 2002, and 2001, respectively. In 2001, the Partnership recorded an impairment charge related to its pipeline assets of $38,049,000. See Note 9. 5. CO2 AND OTHER ASSETS Carbon Dioxide (CO2) Assets We purchased the CO2 assets from Denbury for $24.4 million in cash in November 2003. These assets included the assignment of an interest in 167.5 billion cubic feet (Bcf) of CO2, under a volumetric production payment and Denbury's existing long-term CO2 supply agreements with three of its industrial customers. The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012 and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary adjustments, from us for those transportation services. The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The three industrial contracts extend through 2010, 2012 and 2015. The CO2 assets are being amortized on a units-of-production method. After purchase price adjustments, we had 164.9 Bcf of CO2 at acquisition, and the $24.4 million cost is being amortized based on the volume of CO2 sold each month. For the two months in 2003 when we owned the CO2 assets, we recorded amortization of $328,000. Based on the historical deliveries of CO2 to the customers (which have exceeded minimum take-or-pay volumes), we would expect that amortization for the next five years to be approximately $2,147,000 annually. 63 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Assets Other assets consisted of the following (in thousands).
December 31, ------------------------------ 2003 2002 ------------ ------------ Credit facility fees........................................ $ 1,117 $ 1,312 Covenant not to compete..................................... $ -- $ 4,238 Other....................................................... 40 42 ------------ ------------ 1,157 5,592 Less - Accumulated amortization............................. (297) (4,612) ------------- ------------ Net other assets............................................ $ 860 $ 980 ============ ============
In 2001, the Partnership recorded an impairment charge related to goodwill of $7,012,000, which reduced the net book value of goodwill to zero at December 31, 2001. See Note 11. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," which we adopted January 1, 2002, we test other intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. As of December 31, 2003, no impairment has occurred of our remaining intangible assets. Amortization expense for goodwill was $470,000 for the year ended December 31, 2001. Amortization expense for the covenant-not-to-compete was $205,000 for the year ended December 31, 2003 and $848,000 for the each of the years ended December 31, 2002 and 2001. Accumulated amortization of the covenant-not-to-compete was $4,033,000 at December 31, 2002. The covenant-not-to-compete was fully amortized and expired in 2003. Amortization expense for the credit facility fees for the year ended December 31, 2003 was $298,000. Additionally in 2003, we charged to expense $733,000 of fees related to the facility that existed at the end of 2002. In 2002 and 2001, we recorded $456,000 and $23,000 of amortization of credit facility fees, respectively. 6. DEBT In March 2003, the Partnership entered into $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. The key terms of the Fleet Facility are as follows: - Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%. - The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%. - We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%. - The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. - Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets. - The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum 64 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders. Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under Note 7. At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. We were in compliance with the Fleet Facility covenants at December 31, 2003. 7. PARTNERS' CAPITAL AND DISTRIBUTIONS Partners' Capital During 2001, 2002 and the first ten months of 2003, partnership equity consisted of the general partner interest of 2% and 8.6 million Common Units representing limited partner interests of 98%. The Common Units were sold to the public in an initial public offering in December 1996. In November 2003, we issued 688,811 Common Units to our General Partner in exchange for $4,925,000. We received $101,000 from the general partner for its proportionate capital contribution. At December 31, 2003, a total of 9,313,811 Common Units were outstanding. The general partner interest is held by our General Partner. The Partnership is managed by the General Partner. The General Partner also holds a 0.01% general partner interest in GCOLP, which is reflected as a minority interest in the consolidated balance sheet at December 31, 2003. The Partnership Agreement authorizes the General Partner to cause GCOLP to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other GCOLP needs. Distributions Generally, we will distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 million in total), which was paid in February 2004. Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the quarterly distribution, measured once each month, in order for us to make a distribution for the quarter. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003. 65 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net Income Per Common Unit The following table sets forth the computation of basic net income per Common Unit for 2003, 2002, and 2001 (in thousands, except per unit amounts).
Year Ended December 31, -------------------------------------- 2003 2002 2001 -------- -------- -------- Numerators for basic and diluted net income per common unit: Income (loss) from continuing operations ............... $ (419) $ 1,010 $(13,776) Less general partner 2% ownership ...................... (8) 20 (275) -------- -------- -------- Income (loss) from continuing operations available for common unitholders .................... $ (411) $ 990 $(13,501) ======== ======== ======== Income (loss) from discontinued operations ............. $ 13,741 $ 4,082 $(30,306) Less general partner 2% ownership ...................... 275 82 (606) -------- -------- -------- Income (loss) from continuing operations available for common unitholders .................... $ 13,466 $ 4,000 $(29,700) ======== ======== ======== Cumulative effect of change in accounting principle ........................................... $ -- $ -- $ 467 -------- -------- -------- Less general partner 2% ownership ...................... -- -- 9 -------- -------- -------- Cumulative effect of change in accounting principle available for common unitholders .......... $ -- $ -- $ 458 ======== ======== ======== Denominator for basic and diluted per Common Unit - weighted average number of Common Units outstanding .... 8,715 8,625 8,623 ======== ======== ======== Basic and diluted net income (loss) per Common Unit: Income (loss) from continuing operations ............... $ (0.05) $ 0.11 $ (1.57) Income (loss) from discontinued operations ............. 1.55 0.47 (3.44) Cumulative effect of change in accounting principle .... -- -- 0.05 -------- -------- -------- Net income (loss) ...................................... $ 1.50 $ 0.58 $ (4.96) ======== ======== ========
8. BUSINESS SEGMENT INFORMATION Our operations consist of three operating segments: (1) Crude Oil Gathering and Marketing - the purchase and sale of crude oil at various points along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate and intrastate crude oil pipeline transportation; and (2) CO2 marketing - the sale of CO2 acquired under a volumetric production payment to industrial customers. Prior to 2003, we managed our crude oil gathering, marketing and pipeline operations as a single segment. The tables below reflect all periods presented as though the current segment designations had existed, and include only continuing operations data. We evaluate segment performance based on segment margin before depreciation and amortization. All of our revenues are derived from, and all of our assets are located in the United States. 66 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil ---------------------------- Gathering and CO2 Marketing Pipeline Marketing Total --------- -------- --------- ----- (in thousands) Year Ended December 31, 2003 Revenues: External Customers ............................................. $ 641,684 $ 11,799 $ 1,079 $ 654,562 Intersegment (a) ............................................... -- 3,335 -- 3,335 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $ 641,684 $ 15,134 $ 1,079 $ 657,897 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 7,908 5,108 $ 724 $ 13,740 Capital expenditures ........................................... $ 635 $ 2,302 $ 24,401 $ 27,338 Maintenance capital expenditures ............................... $ 635 $ 2,226 $ -- $ 2,861 Net fixed and other long-term assets ........................... $ 5,480 $ 29,351 $ 24,073 $ 58,904 Year Ended December 31, 2002 Revenues: External Customers ............................................. $ 639,143 $ 10,214 $ -- $ 649,357 Intersegment (a) ............................................... -- 3,271 -- 3,271 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $ 639,143 $ 13,485 $ -- $ 652,628 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 11,177 5,409 $ -- $ 16,586 Capital expenditures ........................................... $ 690 $ 1,981 $ -- $ 2,671 Maintenance capital expenditures ............................... $ 690 $ 1,981 $ -- $ 2,671 Year Ended December 31, 2001 Revenues: External Customers ............................................. $3,001,632 $ 7,809 $ -- $ 654,017 Intersegment (a) ............................................... -- 2,139 -- 2,139 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $3,001,632 $ 9,948 $ -- $3,011,580 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 9,728 2,910 $ -- $ 12,638 Capital expenditures ........................................... $ 388 $ 615 $ -- $ 1,003 Maintenance capital expenditures ............................... $ 388 $ 615 $ -- $ 1,003
(a) Intersegment sales were conducted on an arm's length basis. (b) Segment margin was calculated as revenues less cost of sales and operations expense. A reconciliation of segment margin to income from continuing operations for each year presented is as follows: 67 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, ---------------------------------- 2003 2002 2001 -------- -------- -------- (in thousands) Segment margin excluding depreciation and amortization ........................................ $ 13,740 $ 16,586 $ 12,638 General and administrative expenses ..................... 8,768 7,864 11,307 Depreciation, amortization and impairment ............... 4,641 4,603 14,929 Change in fair value of derivatives ..................... -- 1,279 (1,681) Net gain on disposal of surplus assets .................. (236) (705) (167) Interest expense, net ................................... 986 1,035 527 Other operating charges ................................. -- 1,500 1,500 Minority interests in continuing operations ............. -- -- (1) -------- -------- -------- Income from continuing operations ....................... $ (419) $ 1,010 $(13,776) ======== ======== ========
9. IMPAIRMENT OF PIPELINE ASSETS In the fourth quarter of 2001, as a result of declining revenues and rising costs from its pipeline operations for operations and maintenance combined with regulatory changes requiring additional testing for pipeline integrity, the Partnership determined that the estimated undiscounted future cash flows did not support the carrying value of its pipelines. Under Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121) (the relevant accounting guidance at that time), the carrying value of the assets must be reduced to the fair value of the assets. The estimated fair value of the pipelines was determined by reducing the estimated undiscounted future cash flows plus salvage value to its present value at December 31, 2001. Because the goodwill on the consolidated balance sheet was generated from the acquisition of the pipeline assets, the carrying value of the net goodwill was reduced to zero with the remaining impairment allocated to the fixed assets. An impairment charge totaling $45.1 million was recorded for the pipeline assets and goodwill. $9.6 million of this impairment charge related to continuing operations, with the remaining $35.5 million included in discontinued operations. 10. OTHER OPERATING CHARGES In each of the third quarter of 2002 and the fourth quarter of 2001, the Partnership recorded a charge of $1.5 million, for a total of $3.0 million, related to environmental matters from the Mississippi spill that occurred in 1999. These charges are reflected as other operating charges on the consolidated statement of operations for 2002 and 2001. 11. DISCONTINUED OPERATIONS In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc., which plans to convert the segments to natural gas service. Some remaining segments not sold to these parties were abandoned in place. The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce cost or risk of operation. We determined we should consider selling these assets due to potential risks to the continuation of our revenue stream that may result from consolidation of pipeline assets in the area and projections of maintenance capital costs that may occur. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks. TEPPCO paid us $21.6 million for the assets it acquired. TEPPCO also assumed the responsibilities for unpaid royalties related to the crude oil purchase and sale contracts it assumed and we transferred $0.6 million to TEPPCO for those liabilities. We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us 68 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period. We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to October 31, 2003, subject to certain conditions. TEPPCO will pay the first $25,000 for any environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of these amounts up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO will cease in ten years. During 2003, we recorded $0.4 million in termination benefits related to the sale to TEPPCO. These benefits included retention bonuses and severance pay for employees affected by the sale. Under the terms of the sale to Blackhawk, we received no consideration from Blackhawk for the sale and agreed to provide transition services through March 31, 2004. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years. The assets we abandoned had been idle since 2002 or earlier. The net book value of these assets was charged to impairment expense in 2001. Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:
Year Ended December 31, ---------------------------------------- 2003 2002 2001 --------- --------- --------- (in thousands) Revenues: Gathering and marketing ........................................ $ 263,930 $ 252,452 $ 324,371 Pipeline ....................................................... 6,480 6,726 4,247 --------- --------- --------- Total revenues .............................................. 270,410 259,178 328,618 Costs and expenses: Crude costs .................................................... 256,986 243,262 313,202 Field operating costs .......................................... 4,718 4,535 4,379 Pipeline operating costs ....................................... 5,846 4,852 3,859 General and administrative ..................................... 282 425 384 Depreciation and amortization .................................. 1,864 1,210 2,206 Change in fair value of derivatives ............................ -- 815 (578) Net gain on disposal of surplus assets ......................... -- (3) -- Impairment of long-lived assets ................................ -- -- 35,472 --------- --------- --------- Total costs and expenses .................................... 269,696 255,096 358,924 --------- --------- --------- Operating income from discontinued operations ..................... 714 4,082 (30,306) Gain on disposal of assets ........................................ 13,028 -- -- --------- --------- --------- Income from operations from discontinued Texas System before minority interests ............................... $ 13,742 $ 4,082 $ (30,306) ========= ========= =========
12. TRANSACTIONS WITH RELATED PARTIES Except for below-market guaranty fees paid in 2001 and 2002 to Salomon Smith Barney Holdings Inc. ("Salomon"), sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than those conducted with unaffiliated parties. Salomon was the owner of the General Partner until May 2002. 69 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Sales and Purchases of Crude Oil Denbury became a related party in May 2002. Purchases of crude oil from Denbury for the year ended December 31, 2003, were $59.7 million. Purchases from Denbury during the year ended December 31, 2002, while it was a related party (May to December) were $26.5 million and purchases during the period before it became an affiliate were $10.9 million. Purchases from Denbury are partially secured by letters of credit. Genesis and Salomon ceased to be related parties in May 2002. During the period in 2002 when Salomon was a related party, sales totaling $3.0 million were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases and sales of $36.7 million and $29.8 million, respectively, were made in 2001 with Phibro. These transactions were bulk and exchange transactions. General and Administrative Services We do not directly employ any persons to manage or operate our business. Those functions are provided by the General Partner. We reimburse the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by us were $16,028,000, $17,280,000, and $18,089,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Due to Related Parties At December 31, 2003 and 2002, we owed Denbury $6.9 million and $4.1 million, respectively, for purchases of crude oil. Additionally, we owed Denbury $0.1 million for CO2 transportation services at December 31, 2003. We owed the General Partner $0.1 million and $0.6 million at December 31, 2003 and 2002, respectively, for administrative services. Directors' Fees In 2003, we paid $120,000 to Denbury for the services of four of Denbury's officers who serve as directors of the General Partner, the same rate at which our independent directors were paid. CO2 Volumetric Production Payment and Transportation We acquired a volumetric production payment from Denbury in November 2003 for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2 for us to our customers. For November and December 2003, we paid Denbury $355,000 for these transportation services related to our sales of CO2. See Note 5. Financing Our general partner guarantees our obligations under the Fleet Facility. Our general partner that guarantees the obligations is a wholly-owned subsidiary of Denbury. The obligations are not guaranteed by Denbury or any of its other subsidiaries. Citicorp Credit Agreement In December 2001, Citicorp began providing us with a working capital and letter of credit facility. Citicorp and Salomon are both subsidiaries of Citicorp, Inc. From January 1, 2002, until May 14, 2002, when Citicorp ceased to be a related party, we incurred letter of credit fees, interest and commitment fees totaling $396,000 under the Credit Agreement. In December 2001, we paid Citicorp $900,000 as a fee for providing the facility. This facility fee was being amortized to earnings over the two-year life of the Credit Agreement and was included in interest expense on the consolidated statements of operations. When the facility was replaced in March 2003, the unamortized balance of this fee totaling $371,000 was charged to interest expense. In 2001, the Partnership paid Citicorp for interest and commitment fees totaling $27,000. Guaranty Fees In 2001, Salomon provided a guaranty facility to the Partnership and, from January 2002 to April 2002, Salomon provided guaranties under a transition arrangement with Salomon, Citicorp and the Partnership. For the years ended December 31, 2002 and 2001, the Partnership paid Salomon $61,000 and $1,250,000, respectively, for guarantee fees. The guarantee fees are included as a component in cost of crude on the consolidated statements of operations. These guarantee fees were less than the cost of a letter of credit facility from a bank. 70 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. SUPPLEMENTAL CASH FLOW INFORMATION Cash received by us for interest during the years ended December 31, 2003, 2002 and 2001 was $34,000, $68,000, and $195,000, respectively. Cash payments for interest were $1,194,000, $537,000, and $1,391,000 during the years ended December 31, 2003, 2002 and 2001, respectively. 14. EMPLOYEE BENEFIT PLANS We do not directly employ any of the persons responsible for managing or operating our activities. Employees of the General Partner provide those services and are covered by various retirement and other benefit plans. In order to encourage long-term savings and to provide additional funds for retirement to its employees, the General Partner sponsors a profit-sharing and retirement savings plan. Under this plan, the General Partner's matching contribution is calculated as an equal match of the first 3% of each employee's annual pretax contribution and 50% of the next 3% of each employee's annual pretax contribution. The General Partner also made a profit-sharing contribution of 3% of each eligible employee's total compensation. The expenses included in the consolidated statements of operations for costs relating to this plan were $507,000, $564,000, and $603,000 for the years ended December 31, 2003, 2002 and 2001, respectively. The General Partner also provided certain health care and survivor benefits for its active employees. In 2003, 2002 and 2001, these benefit programs were self-insured, with a catastrophic insurance policy to limit our costs. The General Partner plans to continue self-insuring these plans in the future. The expenses included in the consolidated statements of operations for these benefits were $1,368,000, $1,360,000, and $1,526,000 in 2003, 2002 and 2001, respectively. Stock Appreciation Rights Plan In December 2003, the Board approved a Stock Appreciation Rights (SAR) plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit. The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated his employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below. Upon vesting, the participant may exercise his rights and receive a cash payment calculated as the difference between the average of the closing market price of our Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date. Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested. On December 31, 2003 awards of 423,057 rights were allocated to participants with a strike price of $9.26 per right. In 2003, we recorded non-cash expense of $228,000 for the increase between the strike price of the outstanding rights and the closing market price for Common Units on December 31, 2003. In 2001, we recorded expense of $55,000 related to a restricted unit plan that has been terminated. Bonus Plan In March 2003, the Compensation Committee of the Board of Directors of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the 71 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS financial performance of the Partnership by rewarding all employees for achieving financial performance objectives. The Bonus Plan will be administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash. Bonuses will be paid to employees after the end of the year, but only if distributions are made to the Common Unitholders. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and our General Partner can amend or change the Bonus Plan at any time. 15. MAJOR CUSTOMERS AND CREDIT RISK We derive our revenues from customers primarily in the crude oil industry. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of major international corporate entities with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil Company accounted for 22.5%, 15.4% and 11.0% of total revenues in 2003, respectively. Marathon Ashland Petroleum LLC and ExxonMobil Corporation accounted for 18.5% and 13.6% of total revenues in 2002, respectively. In 2001, BP Amoco Corporation subsidiaries and Enron Corporation subsidiaries accounted for 10.6% and 14.1% of total revenues, respectively. The majority of the revenues from these five customers in all three years relate to our gathering and marketing operations. 16. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities in the Consolidated Balance Sheets approximated fair value due to the short maturity of these instruments. Additionally, the carrying value of the long-term debt approximated fair value due to its floating rate of interest. 17. DERIVATIVES Our market risk in the purchase and sale of its crude oil contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps. Historically, any contracts we have used to hedge market risk were less than one year in duration. During 2003 we did not use any hedging instruments. We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil prices. On January 1, 2001, we adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", which established new accounting and reporting guidelines for derivative instruments and hedging activities. Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset 72 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We mark to fair value our derivative instruments at each period end with changes in fair value of derivatives not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. Unrealized gains or losses on derivative transaction qualifying as hedges are reflected in other comprehensive income. In general, SFAS No. 133 requires that at the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. On January 1, 2001, recognition of our derivatives resulted in a gain of $0.5 million, which was recognized in the consolidated statement of operations as the cumulative effect of adopting SFAS No. 133. Certain derivative contracts related to written option contracts had been recorded on the balance sheet at fair value at December 31, 2000, so no adjustment was necessary for those contracts upon adoption of SFAS No. 133. We regularly review our contracts to determine if the contracts qualify for treatment as derivatives. We had no contracts qualifying for treatment as derivatives at December 31, 2003. At December 31, 2002, we determined that the only contract qualifying as a derivative was a qualifying cash flow hedge. The decrease of $39,000 in the fair value of this hedge is recorded in other comprehensive income and as accumulated other comprehensive income in the consolidated balance sheet. No hedge ineffectiveness was recognized during 2002. The anticipated transaction (crude oil sales) occurred in January 2003, and all related amounts held in other comprehensive income at December 31, 2002, were reclassified to the consolidated statement of operations in the first quarter of 2003. We determined that all other derivative contracts qualified for the normal purchase and sale exemption at December 31, 2003 and 2002. The decrease in fair value of our net asset for derivatives not qualifying as hedges during 2002 was $2.1 million. The increase in fair value of our net asset for derivatives not qualifying as hedges during 2001 was $1.7 million. These changes in fair value are recorded in the consolidated statements of operations under the caption "Change in fair value of derivatives." 18 COMMITMENTS AND CONTINGENCIES Commitments and Guarantees We lease office space for our headquarters office under a long-term lease. The lease extends until October 31, 2005. We lease office space for a field office under a lease that expires in 2007. Ryder provides tractors and trailers to us under an operating lease that also includes full-service maintenance. Under the terms of the lease, we lease 46 tractors and 46 trailers. We pay a fixed monthly rental charge for each tractor and trailer and a fee based on mileage for the maintenance services. We have ordered an additional 5 tractors and trailers from Ryder that we expect to receive during the first quarter of 2004. We lease three tanks for use in our pipeline operations. The tank lease expires in 2004, however we have advised the lessor that we may want to extend the lease. Additionally, we lease a segment of pipeline. Under the terms of that lease, we make lease payments based on throughput, and we have no minimum volumetric or financial requirements remaining. We also lease service vehicles for our field personnel. 73 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The future minimum rental payments under all non-cancelable operating leases as of December 31, 2003, were as follows (in thousands).
Office Tractors and Service Space Trailers Tanks Vehicles Total ------ ------------ ------ -------- ------ 2004 ........................................ $ 489 $1,734 $ 465 $ 360 $3,048 2005 ........................................ 410 2,338 -- 204 2,952 2006 ........................................ 18 559 -- 10 587 2007 ........................................ 15 531 -- -- 546 2008 ........................................ -- 528 -- -- 528 2009 and thereafter ......................... -- 935 -- -- 935 ------ ------ ------ ------ ------ Total minimum lease obligations ............. $ 932 $6,625 $ 465 $ 574 $8,596 ====== ====== ====== ====== ======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 2003............................. $ 4,736 Year ended December 31, 2002............................. $ 4,713 Year ended December 31, 2001............................. $ 4,379
We have guaranteed $3.3 million of residual value related to the leases of tractors and trailers. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote. GELP has guaranteed crude oil purchases of GCOLP. These guarantees, totaling $11.4 million, were provided to counterparties. To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated balance sheet. GELP, the General Partner and the subsidiaries of GCOLP have guaranteed the payments by GCOLP to Fleet under the terms of the Fleet Facility related to borrowings and letters of credit. Borrowings at December 31, 2003 were $7.0 million and are reflected in the consolidated balance sheet. To the extent liabilities exist under the letters of credit, such liabilities are included in the consolidated balance sheet. We have contractual commitments (forward contracts) arising in the ordinary course of our crude oil marketing activities. At December 31, 2003, the Partnership had commitments to purchase 1,854,000 barrels of crude oil in January 2004, and 986,000 barrels of crude oil between February 2004, and October 2004. We had commitments to sell 1,865,000 barrels of crude oil in January 2004, and 690,000 barrels of crude oil between February 2004 and June 2004. All of these contracts are associated with market-price-related contracts. The total commitment to purchase crude oil would be valued at $89.4 million, using market prices at December 31, 2003. The total commitment to sell crude oil would be valued at $82.0 million, using market prices at December 31, 2003. In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards and Securities and Exchange Commission (SEC) regulations. During 2004, we expect to spend between $0.5 million and $1.0 million related to compliance with the requirements of the Sarbanes Oxley Act of 2002 as required by the SEC. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will expend a total of approximately $2.2 million in 2004 and 2005 for testing and rehabilitation under regulations requiring assessment of the integrity of crude oil pipelines. Pennzoil Litigation We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurance carriers settled this litigation for $12.8 million. We have recorded in Accrued Liabilities on our consolidated statement of operations the obligation for this settlement, and in Insurance Receivable we have recorded the insurance reimbursement for this obligation. The settlement was funded in 74 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million was funded by us. We will receive reimbursement of the $6.9 million from the insurance company no later than May 2004. PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter. Environmental On December 20, 1999, we had a spill of crude oil from our Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek nearby. A portion of the oil then flowed into the Leaf River. The oil spill is covered by insurance and the direct financial impact to us of the cost of the clean-up has not been material. Included in insurance receivable on the consolidated balance sheet at December 31, 2003 is $2.8 million related to this spill. Management of the Partnership has reached an agreement in principle with the US Environmental Protection Agency and the Mississippi Department of Environmental Quality for the payment of fines under environmental laws with respect to this oil spill. Based on this agreement in principle, in 2001 and 2002, a total accrual of $3.0 million was recorded for these fines. The fines will not be covered by insurance. We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may substantially affect our business. Other Matters We have taken additional security measures since the terrorist attacks of September 11, 2001 in accordance with guidance provided by the Department of Transportation and other government agencies. We cannot assure you that these security measures would prevent our facilities from a concentrated attack. Any future attacks on us or our customers or competitors could have a material effect on our business, whether insured or not. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Such matters presently pending are not expected to have a material adverse effect on our financial position, results of operations or cash flows. 75 EXHIBIT INDEX Exhibits 3.1 Certificate of Limited Partnership of Genesis Energy, L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545) 3.2 Third Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31, 2002) 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996) 3.4 Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.1 to Form 8-K dated July 31, 2002) 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"), Howell Corporation ("Howell"), certain subsidiaries of Howell, Genesis, the Operating Partnership and Genesis Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for the year ended December 31, 1996) 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended December 31, 1996) 10.3 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) 10.4 Credit Agreement dated as of March 14, 2003, between Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet National Bank and Certain Financial Institutions (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2002) 10.5 Pipeline Sale and Purchase Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and Genesis Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K dated October 31, 2003) 10.6 Purchase and Sale Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K dated October 31, 2003) *10.7 Production Payment Purchase and Sale Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. executed November 14, 2003
*10.8 Carbon Dioxide Transportation Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. *10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan. 11.1 Statement Regarding Computation of Per Share Earnings (See Notes 2 and 7 to the Consolidated Financial Statements) *21.1 Subsidiaries of the Registrant *31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification by Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
---------- * Filed herewith + A management contract or compensation plan or arrangement. EX-10.7 3 h14014exv10w7.txt PROD.PAYMENT PURCHASE AND SALE AGREEMENT 11/14/03 EXHIBIT 10.7 PRODUCTION PAYMENT PURCHASE AND SALE AGREEMENT This PRODUCTION PAYMENT PURCHASE AND SALE AGREEMENT (the "Agreement"), executed as of November 14, 2003, and effective September 1, 2003 (the "Effective Date"), is between DENBURY RESOURCES INC. ("Denbury"), a Delaware corporation, whose address is 5100 Tennyson Parkway, Suite 3000, Plano, Texas 75024, and GENESIS CRUDE OIL, L.P. ("Genesis"), a Delaware limited partnership, whose address is 500 Dallas, Suite 2500, Houston, Texas 77002. Denbury and Genesis are sometimes referred to individually as a "Party" and collectively as the "Parties". FOR AND IN CONSIDERATION of the payments and mutual covenants to be made in this Agreement by the Parties and the benefits derived by the Parties from this Agreement, the Parties agree as follows: RECITALS A. Denbury owns certain undivided oil, gas and mineral leasehold, royalty and mineral interests in and to those lands commonly referred to as the Hollybush field, the South Pisgah field and the Goshen Springs field, as more particularly described in Exhibit A attached to the Assignment (as defined below). B. Denbury is currently engaged in a program with respect to the Subject Interests (as defined below) on the Subject Lands (as defined below) for the exploration, development, production and sale of carbon dioxide. C. Denbury desires to sell and convey and Genesis desires to purchase and pay for (1) all of Denbury's rights, title and interests in and to certain contracts covering the sale of carbon dioxide by Denbury, and (2) a volumetric production payment in and to the carbon dioxide that is produced, saved and sold from the Subject Interests, upon and subject to the terms and conditions provided in the Assignment and this Agreement. I. CERTAIN DEFINITIONS 1.1 For purposes of this Agreement, the following capitalized terms shall have the meanings herein ascribed to them and the capitalized terms defined in the opening paragraph and subsequent paragraphs by inclusion in quotation marks and parentheses shall have the meanings ascribed to them: "Additional Volumes" shall have the meaning given to such term in Section 4.4. "Airgas Contract" means the Industrial Sale Contract identified as the Airgas Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof. "Assigned Contract Interests" shall have the meaning given to such term in Section 4.1. "Assignment" means the Assignment of Production Payment to be entered into between Denbury and Genesis in the form attached hereto as Exhibit A. "Audited Party" shall have the meaning given to such term in Section 12.3. "Bank One Liens" means the liens created under or pursuant to that certain Third Amended and Restated Credit Agreement dated as of September 12, 2002 among Denbury, as borrower, the financial institutions listed therein, Bank One, N.A., as Administrative Agent, Credit Lyonnais New York Branch, and Fortis Capital Corp., as Syndication Agent, and Union Bank of California, as amended by instrument dated effective as of April 30, 2003, and as otherwise amended, supplemented or modified from time to time. "BOC-Brandon Contract" means the Industrial Sale Contract identified as the BOC-Brandon Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof. "Call Option" shall have the meaning given to such term in Section 2.4. "Call Settlement Date" shall have the meaning given to such term in Section 2.4. "Claims" shall have the meaning given to such term in Section 9.1. "Closing" shall have the meaning given to such term in Section 10.1. "Closing Date" shall have the meaning given to such term in Section 10.1. "CO(2)" shall have the meaning given to such term in the Assignment. "Contracts Assignment" means the Assignment of Contracts and Bill of Sale to be entered into between Denbury and Genesis attached hereto as Exhibit C. "Daily Maximum Quantity" shall have the meaning given to such term in the Assignment. "Day" shall have the meaning given to such term in the Assignment. "Deficiency" shall have the meaning given to such term in Section 4.4. "Delivery Points" shall have the meaning given to such term in the T&P Agreement. "Denbury Indemnified Party" shall have the meaning given to such term in Section 9.2. "Denbury Pipeline" shall have the same meaning as "Transporter's Pipeline" as such term is defined in the T&P Agreement. "Effective Date" shall have the meaning given to such term in the opening paragraph of this Agreement. "Environmental Claims" shall have the meaning given to such term in Section 5.14. 2 "Environmental Contaminants" shall have the meaning given to such term in Section 5.14. "Environmental Laws" means all federal, state and local Governmental Requirements regulating or otherwise pertaining to the environment, including without limitation the following as from time to time amended and all others whether similar or dissimilar and whether now existing or hereafter enacted: the Oil Pollution Act of 1990, as amended ("OPA"); the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986; the Resource Conservation and Recovery Act of 1976, as amended by the Used Oil Recycling Act of 1980, the Solid Waste Disposal Act amendments of 1980, and the Hazardous and Solid Waste Amendments of 1984; the Hazardous Materials Transportation Act, as amended; the Toxic Substance Control Act, as amended; the Clean Air Act, as amended; the Clean Water Act, as amended; and all regulations promulgated pursuant thereunder. "Environmental Liabilities" shall have the meaning given to such term in Section 5.14. "Environmental Permits" shall have the meaning given to such term in Section 5.14. "Excess Volumes" shall have the meaning given to such term in the Assignment. "Genesis Indemnified Party" shall have the meaning given to such term in Section 9.1. "Governmental Authority" means any nation or government, any state or other political subdivision thereof and any person exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government. "Governmental Requirement" means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority. "Industrial Sale Contracts" shall have the meaning given to such term in the Contracts Assignment. "Jackson Dome Plant" means the Jackson Dome Processing Plant owned by Denbury located in Brandon, Rankin County, Mississippi. "Leases" means the leases described, referred to or identified in Exhibit A to the Assignment, together with any renewals or extensions of such leases, and any replacement leases, insofar and only insofar as they cover the Subject Lands (or portion thereof). "Lost Interest" shall have the meaning given to such term in Section 11.10. "Master Documents" means this Agreement and all agreements executed in connection herewith or pursuant hereto, including, but not limited to the Assignment, the Contracts Assignment, and the T&P Agreement. 3 "Material Adverse Effect" means a material adverse effect upon (a) the validity or enforceability of the Master Documents, or (b) the financial condition of Denbury or Genesis, as applicable, or (c) the ability of Denbury or Genesis, as applicable, to perform its obligations under the Master Documents. "MCF" shall have the meaning given to such term in the Assignment. "Month" means a period beginning on the first Day of a calendar month and ending at the beginning of the first Day of the next succeeding calendar month. "Permitted Liens" means (a) lessor's royalties, overriding royalties, and division orders covering oil, gas and other hydrocarbons, reversionary interests and similar burdens existing as of the Effective Date; (b) operating agreements, unit agreements and similar agreements, and any and all federal and state regulatory orders and rules (including forced pooling orders) to which the Subject Interests are subject; (c) liens for Taxes or assessments not due or pursuant to which Denbury is not delinquent; (d) preferential rights to purchase and required third-party consents to assignments and similar agreements with respect to which (1) waivers or consents have been obtained from the appropriate parties, or (2) required notice has been given to the holders of such rights and the appropriate time period for asserting such rights has expired without an exercise of such rights; (e) all rights to consent by, required notices to, filings with, or other actions by governmental entities in connection with the sale or conveyance of oil, gas and mineral leases or interests therein if the same are customarily obtained after such sale or conveyance; (f) easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, pipelines, grazing, logging, canals, ditches, reservoirs or the like; and easement for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other easements and rights-of-way, on, over or in respect of any of the Subject Interests; (g) liens of operators relating to obligations not due or pursuant to which Denbury is not delinquent; (h) title problems commonly encountered in the oil and gas business which would not be considered material by a reasonable and prudent person engaged in the business of the ownership, development and operation of oil and gas properties with knowledge of all the facts and appreciation of their legal significance; and (i) the Bank One Liens. "Person" means any individual, natural person, corporation, joint venture, partnership, limited partnership, trust, estate, business trust, association, governmental entity or other entity. "Personal Property" shall mean improvements, machinery, equipment, gathering lines, tanks, fixtures and other personal property and equipment of every kind and nature now or hereafter used or held for use in connection with the exploration, development or operation of the Subject Interests; provided, however, that the term "Personal Property" shall not include the Denbury Pipeline or the Jackson Dome Plant. "Praxair Contract" means the Industrial Sale Contract identified as the Praxair Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof. "Production Payment" shall have the meaning given to such term in the Assignment. "Production Payment Gas" shall have the meaning given to such term in the Assignment. 4 "Receipt Point" shall have the meaning given to such term in the T&P Agreement. "Reserve Report" shall mean "Data on Estimated Proved Carbon Dioxide Reserves as of December 31, 2002" of the Appraisal Report as of December 31, 2002 on Certain Properties Owned by Denbury Resources Inc., SEC Case, of DeGolyer and MacNaughton dated February 4, 2003. "Retained Obligations" shall have the meaning given to such term in Section 11.12. "Scheduled Delivery Volumes" shall have the meaning given to such term in the Assignment. "Subject Interests" shall have the meaning given to such term in the Assignment. "Subject Lands" shall have the meaning given to such term in the Assignment. "Taxes" shall have the meaning given to such term in the Assignment. "Term" shall have the meaning given to such term in the Assignment. "T&P Agreement" means the Carbon Dioxide Transportation Agreement to be entered into between Denbury and Genesis in the form attached hereto as Exhibit D. "Transportation Fee" shall have the meaning given to such term in the T&P Agreement. II. PURCHASE AND SALE OF THE PRODUCTION PAYMENT 2.1 Subject to the terms of this Agreement, Denbury agrees to sell and convey and Genesis agrees to purchase and pay for the Production Payment. 2.2 The Production Payment will be assigned by Denbury to Genesis pursuant to the Assignment. 2.3 Genesis shall look solely to the receipt of Production Payment Gas as provided herein for satisfaction and discharge of the Production Payment, and Genesis shall not have any other recourse against Denbury for the payment and discharge of the Production Payment. However, the foregoing provision shall not relieve Denbury of any obligation to respond in damages for any breach of any of the covenants, agreements and obligations of Denbury hereunder or under any other Master Document. 2.4 Genesis hereby grants Denbury the option to repurchase the Production Payment pursuant to the terms of this Section 2.4 (the "Call Option"). If pursuant to Section 2.8 of the T&P Agreement, the Transporter (as defined in the T&P Agreement) elects to exercise its Call Option (or is deemed to have elected to exercise its Call Option), Denbury shall notify Genesis of the date on which the repurchase will be consummated (the "Call Settlement Date"), which date must be a Business Day and must occur no sooner than five Business Days and no later than 30 days after the date on which Transporter delivered (or was deemed to have delivered) notice 5 of its intent to exercise the Call Option. On the Call Settlement Date, Genesis and Denbury shall execute documentation sufficient to terminate the Production Payment and the other Master Documents, cause the reconveyance to and assumption by Denbury of the Industrial Sale Contracts, and contemporaneously therewith, Denbury shall pay to Genesis in immediately available funds, a purchase price equal to the estimated cash flow from the remaining volumes obligated to be delivered pursuant to the Production Payment discounted to present net value using a fifteen percent (15%) per annum discount rate. The estimated cash flow from the remaining volumes obligated to be delivered pursuant to the Production Payment shall be based upon a forecast prepared by Denbury and furnished to Genesis, and if Genesis objects to such forecast, then such matter may be submitted to and resolved in accordance with the arbitration provisions contained in Article XIV. 2.5 In the event of any express conflict between the terms and provisions of this Agreement and the terms and provisions of the Assignment, the terms and provisions of the Assignment shall control. The inclusion in this Agreement of provisions not addressed in the Assignment shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect. III. PROCESSING AND TRANSPORTATION OF PRODUCTION PAYMENT GAS 3.1 After Closing, Denbury agrees to transport Production Payment Gas from the Receipt Points, and redeliver Production Payment Gas at the Delivery Points, in accordance with the provisions of the T&P Agreement. All Production Payment Gas shall be delivered by Denbury to the Delivery Points in compliance with the requirements set out in the T&P Agreement with respect to pressure, quantity and quality specifications. Under the T&P Agreement, Genesis will pay Denbury a Transportation Fee (as adjusted in accordance with the terms of the T&P Agreement), which initially shall be $0.16 per MCF, for transportation of the Production Payment Gas from the Receipt Points, processing of the Production Payment Gas through the Jackson Dome Plant, and redelivery of the Production Payment Gas to or on behalf of Genesis at the Delivery Points. 3.2 The processing and transportation of Production Payment Gas by Denbury as described in this Article shall be subject to the terms and provisions contained in this Article, as such terms and provisions may be further described or supplemented by the T&P Agreement. In the event of any conflict between the terms and provisions of this Article and the terms and provisions of the T&P Agreement, the terms and provisions of the T&P Agreement shall control. The inclusion in this Agreement of provisions not addressed in the T&P Agreement shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect. IV. ASSIGNMENT OF INDUSTRIAL SALE CONTRACTS 4.1 At Closing, Denbury will assign to Genesis all of its rights and interests in and to the Industrial Sale Contracts (the "Assigned Contract Interests"), subject to the terms and conditions contained in the Industrial Sale Contracts. The Assigned Contract Interests will be 6 assigned by Denbury to Genesis pursuant to the Contracts Assignment. Notwithstanding such assignment, Denbury shall be obligated to continue to comply with the Retained Obligations. 4.2 At Closing, Genesis will assume the cost and responsibilities of administering the Assigned Contract Interests with respect to rights and obligations arising after the Effective Date and will report the sales and values of such sales to Denbury on a Monthly basis on or before the 10th day of each succeeding Month, in a manner and format agreed upon between the Parties, in order that Denbury can timely pay royalties attributable to the Production Payment Gas sold pursuant to the Industrial Sale Contracts. Notwithstanding anything herein to the contrary, without the prior written consent of Denbury, Genesis shall not amend or otherwise modify any terms or provisions of any of the Industrial Sale Contracts if such amendment or modification of the Industrial Sale Contracts shall in any manner whatsoever, directly or indirectly, modify the Retained Obligations or otherwise increase any obligations of Denbury under any of the Master Documents, including but not limited to any increase of the sales and delivery requirements under the Industrial Sale Contracts. If Denbury elects not to consent to any proposed amendment, Denbury shall provide a written explanation setting out the reasons for such election. 4.3 In the event of any conflict between the terms and provisions contained in this Article and the terms and provisions of the Contracts Assignment, the terms and provisions contained in the Contracts Assignment shall control. The inclusion in this Agreement of provisions not addressed in the Assignment shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect. 4.4 If at any time or from time to time during the Term Genesis determines that 167.5 million MCF is not sufficient to satisfy the sales and delivery requirements of the Industrial Sale Contracts (a "Deficiency"), Genesis shall promptly furnish Denbury with written notice of such determination, and such notice shall contain sufficient detail that is reasonably calculated to enable Denbury to determine the basis for Genesis' determination of such Deficiency. If, after receipt of such notice, Denbury agrees with Genesis' assessment of a Deficiency, Denbury agrees to amend the Production Payment to include such additional volumes of CO(2) that are necessary to enable Genesis to satisfy the sales and delivery requirements of the Industrial Sale Contracts. If Denbury fails to agree with Genesis' assessment of a Deficiency, then such matter shall be resolved pursuant to Article XIV. The agreed-upon amount of additional volumes necessary to enable Genesis to satisfy the sales and delivery requirements of the Industrial Sale Contracts (the "Additional Volumes") shall be sold by Denbury to Genesis on the same terms and conditions, mutatis mutandis, as applicable to the Production Payment by virtue of this Agreement, and the value of, and consequently the consideration to be paid by Genesis to Denbury for, the Additional Volumes shall be calculated based on estimated cash flow from the Additional Volumes discounted to present net value using a fifteen percent (15%) per annum discount rate. Notwithstanding the foregoing, if it is determined that the Deficiency has occurred, in whole or in part, as a result of the sale by Genesis of Excess Volumes, Denbury shall not be obligated to deliver those Additional Volumes which are attributable to the sale of Excess Volumes by Genesis. 7 V. REPRESENTATIONS AND WARRANTIES OF DENBURY Denbury hereby represents and warrants to Genesis as follows: 5.1 Denbury is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware. Denbury possesses the legal right, power and authority, and qualifications to conduct its business and own its properties (including the Subject Interests), except where the failure to so possess would not, individually or collectively, have a Material Adverse Effect. Denbury has the legal right, power and authority (i) to execute and deliver the Assignment and to convey to Genesis the Production Payment and all of the rights and privileges appurtenant thereto and (ii) to execute and deliver this Agreement and the other Master Documents and to perform all of its obligations hereunder and thereunder. 5.2 The execution, delivery and performance by Denbury of this Agreement and the other Master Documents are within its corporate powers and authority, have been duly authorized by all necessary board of director action on the part of Denbury and do not and will not (i) violate any Governmental Requirement currently in effect having applicability to Denbury, other than violations which would not, individually or collectively, cause a Material Adverse Effect, or (ii) violate any provision of Denbury's articles of incorporation, bylaws, or other governing documents, or (iii) result in a breach of or constitute a default (excluding breaches or defaults which, individually or collectively, would not have a Material Adverse Effect) under any indenture, bank loan, or credit agreement or farm-out agreement, program agreement or operating agreement, or any other agreement or instrument to which Denbury is a party or by which Denbury or its properties may be currently bound or affected, or (iv) other than the Master Documents and/or other than matters which would not individually or collectively cause a Material Adverse Effect, result in or require the creation or imposition of any mortgage, lien, pledge, security interest, charge, or other encumbrance upon or of any of the properties or assets of Denbury (including the Subject Interests). 5.3 This Agreement and the other Master Documents have been duly executed and delivered by Denbury, and this Agreement and the Master Documents constitute the legal, valid, and binding acts and obligations of Denbury enforceable against Denbury in accordance with their terms, subject, however, to bankruptcy, insolvency, reorganization, and other laws affecting creditors' rights generally and general principles of equity. There are no bankruptcy, insolvency, reorganization, receivership or arrangement proceedings pending, being contemplated by or, to Denbury's knowledge, threatened against Denbury. 5.4 Denbury is not in default under any Governmental Requirement, indenture, agreement, or instrument which would reasonably be expected to cause a Material Adverse Effect nor does any fact or condition exist at this time that would reasonably be expected to cause a Material Adverse Effect in the future under any Governmental Requirement, indenture, agreement or instrument; and all consents and waivers of preferential purchase or other rights required in connection with the valid conveyance to Genesis of the Production Payment or the execution and delivery of this Agreement and the other Master Documents have been obtained or the time for giving such consents or waivers has expired following a written request therefor, 8 other than those consents and waivers which if not obtained, would not individually or collectively have a Material Adverse Effect. 5.5 All advance notifications to third parties of the transactions contemplated herein and in the other Master Documents required in connection with the valid conveyance to Genesis of the Production Payment or execution and delivery of this Agreement and the other Master Documents have been timely and properly given, other than those notifications which, if not obtained, would not individually or collectively have a Material Adverse Effect. 5.6 All authorizations, consents, approvals, licenses, and exemptions of, and filings or registrations with, any Governmental Authority, that are required for the valid execution and delivery by Denbury of, or the performance by Denbury of its obligations under, this Agreement or the other Master Documents have been obtained or performed or the period for objection thereto expired, other than those which, if not obtained or performed, would not individually or collectively have a Material Adverse Effect. 5.7 To Denbury's knowledge, the Reserve Report (i) was prepared in accordance with customary engineering practices, and (ii) is based on historical information that is accurate and complete in all material respects. The Subject Interests constitute all of the properties and interests reflected in the Reserve Report that relate to the production of CO(2). Set forth on Exhibit B is a true and correct statement of Denbury's working interest and net revenue interest in and to each well noted on Exhibit B except to the extent that such interest is incorrect as the result of an act or omission that does not arise by, through or under Denbury and except for discrepancies which would not be considered material by a reasonable and prudent person engaged in the business of the ownership, development and operation of oil and gas properties with knowledge of all the facts and appreciation of their legal significance. The interests reflected on Exhibit B are owned by Denbury free and clear of any lien or encumbrance arising by, through or under Denbury, other than Permitted Liens. 5.8 All Taxes imposed or assessed with respect to or measured by or charged against or attributable to the Subject Interests, the Personal Property, the Denbury Pipeline and the Jackson Dome Plant have been duly paid, except for Taxes not yet due and payable or pursuant to which Denbury is not delinquent. 5.9 There are no suits or proceedings pending or, to Denbury's knowledge, threatened against Denbury, the Subject Interests, the Denbury Pipeline, the Jackson Dome Plant or any of the Personal Property before any Governmental Authority, that, if decided adversely to the interest of Denbury, would reasonably be expected to have a Material Adverse Effect; provided, however, that notwithstanding the foregoing, Schedule 5.9 includes a list of current litigation affecting Denbury, the Subject Interests, the Denbury Pipeline, the Jackson Dome Plant or the Personal Property. 5.10 Except with respect to those matters which would not individually or collectively have a Material Adverse Effect, (i) the Leases are in full force and effect, and (ii) Denbury has complied with the terms of all Governmental Requirements applicable to Denbury or applicable directly to the Subject Interests. 9 5.11 All rents and royalties with respect to the Leases have been paid in a timely manner (excluding any failures to pay which would not individually or collectively have a Material Adverse Effect), and all liabilities of any kind or nature incurred with respect to the Leases have been paid before delinquent (excluding any liabilities or failures to pay which would not individually or collectively have a Material Adverse Effect); Denbury has not received any notice of default or claimed default with respect to the Subject Interests or any part thereof that would reasonably be expected to result in a Material Adverse Effect; and except for matters which would not individually or collectively have a Material Adverse Effect, all wells, facilities and equipment which constitute part of the Personal Property and the Denbury Pipeline and the Jackson Dome Plant are in good repair and working condition and have been designed, installed and maintained in accordance with generally accepted industry standards and all applicable Governmental Requirements. 5.12 Denbury has not violated any Governmental Requirement or failed to obtain any license, permit, franchise or other governmental authorization required for the ownership or operation of any of the Personal Property or the Denbury Pipeline or the Jackson Dome Plant, except for violations which would not individually or collectively have a Material Adverse Effect. Except for matters which would not individually or collectively have a Material Adverse Effect, the Personal Property, the Denbury Pipeline and the Jackson Dome Plant have each been maintained, operated and developed in conformity with all applicable Governmental Requirements of all Governmental Authorities having jurisdiction and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Subject Interests. 5.13 Since the December 31, 2002, there has not been any reduction in the rate of production of CO(2) from any of the Subject Interests that would reasonably be expected to have a Material Adverse Effect. 5.14 Except as set forth on Schedule 5.14 and except with respect to those matters which would not individually or collectively reasonably be expected to result in a Material Adverse Effect, to Denbury's knowledge: (i) Denbury has obtained and maintained in effect all environmental and health and safety permits, licenses, approvals, consents, certificates and other authorizations required in connection with Denbury's ownership or operation of the Subject Lands ("Environmental Permits"); (ii) Denbury's operations on the Subject Lands are in compliance in all material respects with all applicable Environmental Laws and with all terms and conditions of all applicable Environmental Permits, and all prior instances of material non-compliance have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters; (iii) Denbury's operations on the Subject Lands are not subject to any third party environmental or health and safety claim, demand, filing, investigation, administrative proceeding, action, suit or other legal proceeding, whether direct, indirect, contingent, pending, threatened or otherwise ("Environmental Claim"), or Environmental Liabilities (as defined herein), arising from, based upon, associated with or related to Denbury's operations on the Subject Lands; (iv) Denbury has not received any notice of any Environmental Claim, Environmental Liabilities or any violation or non-compliance with any Environmental Law or the terms or conditions of any Environmental Permit, arising from, based upon, associated with or related to Denbury's operations on the Subject Lands; (v) no pollutant, waste, contaminant, or hazardous, extremely hazardous, or toxic material, substance, chemical or waste identified, defined or regulated as such under any Environmental Law 10 ("Environmental Contaminants") is present on, or has been handled, managed, stored, transported, processed, treated, disposed of, released, migrated or has escaped on, in, from, or under the Subject Lands as a result of Denbury's operations on the Subject Lands in a manner that has caused an Environmental Claim, Environmental Liabilities or a violation of any applicable Environmental Law; and (iv) the executive management of Denbury is not aware of any facts, conditions or circumstances in connection with, related to or associated with any of the Properties or the ownership or operation, that as of the date of this Agreement could reasonably be expected to give rise to any material Environmental Claim or Environmental Liabilities. As used in this Agreement, the term "Environmental Liabilities" shall mean any and all liabilities arising from, based upon, associated with or related to (i) any Environmental Claim, (ii) any applicable Environmental Permit, (iii) any applicable Environmental Law or (iv) the presence, handling, management, storage, transportation, processing, treatment, disposal, release, threatened release, migration or escape of Environmental Contaminants (including, without limitation, all costs arising under any theory of recovery, in law or at equity), whether based on negligence, strict liability, or otherwise, including, without limitation, remediation, removal, response, restoration, abatement, investigative, monitoring, personal injury, and property damage costs and all other related costs, expenses, losses, damages, penalties, fines, liabilities and obligations (including interest paid or accrued, attorneys' fees, and court costs). 5.15 Denbury has good title to each of the Industrial Sale Contracts, free and clear of all liens, encumbrances or claims (other than (i) Permitted Liens and (ii) the right of first refusal set out in the Airgas Contract), and each Industrial Sale Contract is, in full force and effect and enforceable against Denbury and, to Denbury's knowledge, the counterparty thereto. The Industrial Sale Contracts have been conveyed to Genesis free and clear of the Bank One Liens. 5.16 Except as set forth on Schedule 5.9 or Exhibit A to the Contracts Assignment, (a) there are no have been no amendments or modifications to the Industrial Sale Contracts; and (b) there are no breaches or defaults under any Industrial Sale Contract by Denbury or any counterparty to any Industrial Sale Contract which would reasonably be expected to prevent the practical realization by Genesis of the benefits intended to be provided to Genesis under such Industrial Sale Contract. 5.17 Upon due execution and delivery by Denbury of the Assignment, under Mississippi law, (i) the Assignment will constitute the legal, valid, and binding conveyance of the Production Payment and will constitute a burden upon all of the CO(2) production from the Subject Interests, and (ii) the Production Payment will constitute real property. 5.18 Except with respect to the Industrial Sale Contracts and/or as set forth in Schedule 5.18, (i) neither the Subject Interests, the CO(2) attributable thereto nor the Denbury Pipeline are subject, committed or dedicated to any contract, agreement or arrangement regarding the transportation or sale of CO(2) production; (ii) no third party has any call, right of first refusal or preferential right to purchase or transport any such CO(2) that has not been waived or the time for giving such consents or waivers has expired in accordance with the terms of such call or rights; and (iii) no third party has any purchase option with respect to any such CO(2) or the Denbury Pipeline. 11 VI. REPRESENTATIONS AND WARRANTIES OF GENESIS Genesis hereby represents and warrants to Denbury as follows: 6.1 Genesis is a limited partnership duly formed and validly existing under the laws of the State of Delaware. Genesis possesses the legal right, power and authority, and qualifications to conduct its business and own its properties, except where the failure to so possess would not, individually or collectively, have a Material Adverse Effect. Genesis has the legal right, power and authority to execute and deliver this Agreement, the Assignment and the other Master Documents and to perform all of its obligations hereunder and thereunder, including unanimous approval of the transactions by the audit committee of Genesis Energy, Inc., the general partner of Genesis, such audit committee consisting solely of independent directors (the "Audit Committee"). 6.2 The execution, delivery and performance by Genesis of this Agreement and the other Master Documents are within its powers and authority, have been duly authorized by all necessary board of director action on the part of Genesis Energy, Inc., (in its capacity as general partner of Genesis) and by the Audit Committee and do not and will not (i) violate any Governmental Requirement currently in effect having applicability to Genesis, other than violations which would not, individually or collectively, cause a Material Adverse Effect, or (ii) violate Genesis' limited partnership agreement or other governing documents, or (iii) result in a breach of or constitute a default (excluding breaches or defaults which, individually or collectively, would not have a Material Adverse Effect) under any indenture, bank loan, or credit agreement or farm-out agreement, program agreement or operating agreement, or any other agreement or instrument to which Genesis is a party or by which Genesis or its properties may be currently bound or affected. 6.3 Genesis is not in default under any Governmental Requirement, indenture, agreement, or instrument that would reasonably be expected to cause a Material Adverse Effect nor does any fact or condition exist at this time that would reasonably be expected to cause a Material Adverse Effect now or in the future under any Governmental Requirement, indenture, agreement or instrument; and all consents or approvals under such indentures, agreements, and instruments necessary to permit the valid execution, delivery, and performance by Genesis of the Master Documents have been obtained. 6.4 This Agreement and the other Master Documents have been duly executed and delivered by Genesis, and this Agreement and the Master Documents constitute the legal, valid, and binding acts and obligations of Genesis enforceable against Genesis in accordance with their terms, subject, however, to bankruptcy, insolvency, reorganization, and other laws affecting creditors' rights generally and general principles of equity. There are no bankruptcy, insolvency, reorganization, receivership or arrangement proceedings pending, being contemplated by or, to the knowledge of Genesis, threatened against Genesis. 6.5 All authorizations, consents, approvals, licenses, and exemptions of, and filings or registrations with, any Governmental Authority, that are required for the valid execution and delivery by Genesis of, or the performance by Genesis of its obligations under, this Agreement 12 or the other Master Documents have been obtained or performed or the period for objection thereto expired, other than those which, if not obtained or performed, would not individually or collectively have a Material Adverse Effect; and no consent or vote of the limited partners of Genesis is required for the execution, delivery or performance by Genesis of this Agreement and the other Master Documents under Genesis' limited partnership agreement or other documents to which Genesis is a party. 6.6 There are no suits or proceedings pending or, to Genesis' knowledge, threatened against Genesis before any Governmental Authority, that if decided adversely to the interest of Genesis would reasonably be expected to have a Material Adverse Effect. 6.7 The Production Payment to be acquired by Genesis pursuant to this Agreement is being acquired for Genesis' own account and for investment and not for distribution in violation of applicable securities laws. VII. PAYMENT TO DENBURY 7.1 As consideration for the sale of the Production Payment to Genesis and the assignment of the Assigned Contract Interests to Genesis by Denbury, Genesis shall pay to Denbury at Closing, $24,925,000 in cash. VIII. DISCLAIMER OF WARRANTIES 8.1 Denbury has allowed Genesis the opportunity to review the title to the Subject Interests, to satisfy itself as to all matters pertaining to the transactions contemplated by this Agreement, including but not limited to the sufficiency of CO(2) reserves attributable to the Subject Interests to satisfy the CO(2) delivery requirements under the Assigned Contract Interests, and to conduct other due diligence with respect to the Production Payment, the Subjects Interests, the Subject Lands, the Denbury Pipeline, the Jackson Dome Plant and the Industrial Sale Contracts as Genesis deems necessary to consummate the transactions contemplated by this Agreement. 8.2 OTHER THAN THE EXPRESS REPRESENTATIONS AND WARRANTIES PROVIDED BY DENBURY HEREIN AND IN THE OTHER MASTER DOCUMENTS, DENBURY MAKES NO WARRANTIES AS TO (i) THE PRESENCE, QUALITY AND QUANTITY OF CO(2) RESERVES ATTRIBUTABLE TO THE SUBJECT INTERESTS, (ii) THE AMOUNT, VALUE, QUALITY, QUANTITY, VOLUME OR DELIVERABILITY OF ANY CO(2) OR CO(2) RESERVES IN, UNDER OR ATTRIBUTABLE TO THE SUBJECT LANDS, (iii) THE GEOLOGICAL OR ENGINEERING CONDITION OF THE SUBJECT LANDS, (iv) THE ABILITY OF THE SUBJECT LANDS TO PRODUCE CO(2), INCLUDING WITHOUT LIMITATION, PRODUCTION RATES, DECLINE RATES AND RECOMPLETION OPPORTUNITIES, (v) ANY PROJECTIONS AS TO EVENTS THAT COULD OR COULD NOT OCCUR, (vi) THE ACCURACY, COMPLETENESS, OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO GENESIS IN CONNECTION WITH THE SUBJECT INTERESTS, SUBJECT LANDS, THE 13 DENBURY PIPELINE AND JACKSON DOME PLANT, INCLUDING INFORMATION CONTAINED IN ANY EXHIBIT OF THIS AGREEMENT, ANY SEISMIC DATA AND DENBURY'S INTERPRETATION OR ANALYSIS OF SAME, OR (VII) ANY OTHER MATTERS CONTAINED IN OR OMITTED FROM ANY INFORMATION OR MATERIAL FURNISHED TO GENESIS BY DENBURY. ANY DATA, INFORMATION OR OTHER RECORDS FURNISHED BY DENBURY ARE PROVIDED TO GENESIS AS A CONVENIENCE AND GENESIS' RELIANCE ON OR USE OF THE SAME IS AT GENESIS' SOLE RISK. IX. INDEMNITY 9.1 Denbury hereby indemnifies Genesis and its successors and assigns and affiliates (each a "Genesis Indemnified Party") against, and agrees to defend and hold each Genesis Indemnified Party harmless from and against, any and all obligations, liabilities, claims, demands, suits, debts, accounts, liens or encumbrances, and all costs and expenses, including reasonable attorneys' fees relating thereto (collectively, "Claims"), that any Genesis Indemnified Party may suffer or incur and that result from (a) the ownership or operation of the Subject Interests, (b) the ownership of the Industrial Sale Contracts prior to the Effective Date, (c) any inaccuracy of any representation or warranty of Denbury contained in this Agreement or in any other Master Document, (d) any breach of any covenant or agreement of Denbury contained in this Agreement or in any other Master Document, including but not limited to the covenants relating to the Retained Obligations; provided, however, that such indemnification shall not be construed to cover or include any of the matters identified in Section 8.2 (including but not limited to disclaimers of warranties relating to CO(2) reserves or production) or any Claims to the extent, but only to the extent, such Claims are determined to be not payable because they fall within the scope of the force majeure provisions contained in the Master Documents or the Industrial Sale Contracts. 9.2 Genesis hereby indemnifies Denbury and its successors and assigns and Affiliates (each a "Denbury Indemnified Party") against, and agrees to defend and hold each Denbury Indemnified Party harmless from and against, any and all Claims that each Denbury Indemnified Party may suffer or incur and that result from (a) except to the extent of any Claims arising solely as a result of Denbury's execution of the Assignment, the ownership or operation of the Production Payment, (b) except to the extent of any Claims arising as a result of Denbury's failure to comply with the Retained Obligations, the ownership of the Industrial Sale Contracts after the Effective Date, (c) any inaccuracy of any representation or warranty of Genesis contained in this Agreement or any other Master Document, or (d) any breach of any covenant or agreement of Genesis contained in this Agreement or any other Master Document; provided, however, that such indemnification shall not be construed to cover or include any Claims to the extent, but only to the extent, such Claims are determined to be not payable because they fall within the scope of the force majeure provisions contained in the Master Documents or the Industrial Sale Contracts. 9.3 No person entitled to indemnification hereunder or otherwise to damages in connection with or with respect to the transactions contemplated in the Agreement and the other Master Documents shall settle, compromise or take any other action with respect to any Claim 14 that could prejudice or otherwise adversely impact the ability of the person providing such indemnification or potentially liable for such damages to defend or otherwise settle or compromise with respect to such Claim. 9.4 Each Party entitled to indemnification hereunder or otherwise to damages in connection with the transactions contemplated in Agreement or the other Master Documents shall take all reasonable steps to mitigate all losses, costs, expenses and damages after becoming aware of any event or circumstance that could reasonably be expected to give rise to any losses, costs, expenses and damages that are indemnifiable or recoverable hereunder or in connection herewith. 9.5 The indemnification provisions provided for in this Agreement shall be applicable whether or not the losses, costs, expenses and damages in question arose solely or in part from the gross, active, passive or concurrent negligence, strict liability or other fault of Genesis or Denbury, as applicable. The parties acknowledge that this statement complies with the express negligence rule and is conspicuous. X. CLOSING 10.1 Unless the Parties otherwise agree in writing, the closing of the transactions contemplated by this Agreement (the "Closing") will occur on the date this Agreement is executed as first set forth above (the "Closing Date") 10.2 At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others: (a) Genesis shall deliver to Denbury the cash consideration described in Section 7.1 by wire transferring immediately available funds to the account of Denbury pursuant to wiring instructions furnished by Denbury to Genesis prior to the Closing Date; (b) The Parties shall execute, acknowledge and deliver the Assignment and the Contracts Assignment; (c) The Parties shall execute and deliver the T&P Agreement; (d) Denbury shall obtain and deliver to Genesis multiple executed originals of the Agreement with Lenders executed by the holders of the Bank One Liens, in form and substance substantially similar to the Agreement with Lenders attached hereto as Exhibit F; (e) Denbury shall obtain and deliver to Genesis multiple executed originals of an acceptable release of liens with respect to the Bank One Liens encumbering the Subject Interests conveyed to Genesis pursuant to the Assignment; and 15 (f) The Parties shall execute and deliver any other documents or instruments necessary or appropriate to effect or support the transactions contemplated in this Agreement. 10.3 Promptly following the Closing, Genesis will cause counterparts of the Assignment, a mutually agreeable Memorandum of T&P Agreement, Agreement with Lenders and financing statements to be filed for record in all appropriate records in appropriate filing locations. Genesis will pay for all documentary, filing and recording fees required in connection with the filing and recording of the Master Documents. XI. COVENANTS AND AGREEMENTS OF DENBURY During the Term, and unless Genesis otherwise agrees in writing, Denbury covenants as follows, and agrees and undertakes, to perform each and all of the following covenants at Denbury's sole and entire cost and expense: 11.1 Denbury will (without regard to the burden of the Production Payment) conduct and carry on the development, maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil and gas field practices and all applicable Governmental Requirements, and will drill such wells as a reasonably prudent operator would drill from time to time in order to develop the Subject Interests and to protect them from drainage. Nothing contained in this Section, however, shall be deemed to prevent or restrict Denbury from electing not to participate in any operation that is to be conducted under the terms of any operating agreement, unit operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Denbury in good faith and in conformity with sound field practices. After the date of this Agreement, Denbury shall not enter into any transaction(s) or agree to any arrangements which, after taking into account then current required third party sales (including sales under the Industrial Sale Contracts) and Denbury's and its affiliates' usage, would result or be reasonably anticipated to result in an inability of Denbury to deliver the Scheduled Delivery Volumes to Genesis. 11.2 Denbury shall not voluntarily abandon any well heretofore or hereafter completed for production of CO(2) on any of the Subject Lands or surrender, abandon or release any Subject Interest or any part thereof; provided however, that nothing in this Agreement shall obligate Denbury to continue to operate any well or to operate or maintain in force or attempt to maintain in force any Lease when, in Denbury's reasonable opinion, exercised in good faith and as would a prudent operator not burdened by the Production Payment, such well or Lease ceases to produce or is not capable of producing in paying quantities (without regard to the burden of the Production Payment) and it would not be economically practical, in Denbury's reasonable judgment (determined without regard to the burden of the Production Payment), to restore the productivity of such well by reworking, reconditioning, deepening, or plugging back such well. The expiration of a Lease in accordance with its terms and conditions shall not be considered to be a voluntary surrender or abandonment of such lease. 16 11.3 With respect to all oil, gas and mineral leases included in the Subject Interests, Denbury will in all material respects comply with, or cause to be complied with, all pertinent Governmental Requirements that from time to time are promulgated to regulate the production and sale or production or sale of CO(2). 11.4 Certain of the Subject Interests may have been heretofore pooled and unitized for the production of CO(2). Such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Production Payment shall apply to and affect only that portion of the production from such units that accrues to such Subject Interests as burdened, encumbered or otherwise affected by any and all applicable pooling and unitization agreements. Denbury shall have the right and power to pool and unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the Subject Lands, upon such terms and provisions as Denbury shall in its sole discretion determine. If and whenever through the exercise of such right and power, or pursuant to any Governmental Requirement hereafter enacted, any of the Subject Interests are pooled or unitized in any manner, the Production Payment, insofar as it affects such pooled or unitized Subject Interests shall also be pooled and unitized, and in any such event such Production Payment shall apply to and affect only the production that accrues to such Subject Interests, as burdened, encumbered or otherwise affected by such pooling and unitization. 11.5 Denbury shall pay, or cause to be paid, before delinquent, all Taxes, except Taxes being contested in good faith. In the event that after the expiration of the Term, additional Taxes should be charged against Genesis which are attributable to Production Payment Gas produced during the Term and delivered to Genesis at the Receipt Point(s), Denbury shall be obligated to pay such Taxes. 11.6 Subject to the provisions of Section 2.4 hereof and Section 2.8 of the T&P Agreement, Denbury will at all times maintain, preserve and keep all Personal Property, the in good repair, working order and condition in all material respects, and promptly make all necessary and proper repairs, renewals, replacements and substitutions, to the end that the value of such Personal Property, shall in all material respects be fully preserved and kept in such condition as at all times to permit the most efficient and economical use and operation thereof. 11.7 Denbury will (i) use all commercially reasonable efforts to promptly pay, or cause to be paid, as and when due and payable all material rentals and royalties payable in respect of the Subject Interests or the production therefrom, and all material costs, expenses and liabilities for labor and material to the extent that the same are attributable to the Subject Interests, the Personal Property, the Denbury Pipeline or the Jackson Dome Plant, (ii) never permit any lien (other than Permitted Liens) to be affixed or burden the Subject Interests or Personal Property, even though inferior to the Production Payment, for any such bills which may be legally due and payable (other than Permitted Liens or liens which, individually or collectively, could not have a Material Adverse Effect), and (iii) never permit to be created or to exist in respect to any of the Subject Interests or the Personal Property, any other or additional lien on a parity with or superior to the Production Payment, except for Permitted Liens or other than liens which, individually or collectively, could not have a Material Adverse Effect. 17 11.8 Denbury shall not resign as operator of any Subject Interest operated by Denbury until and unless the successor operator has been approved in writing by Genesis, such approval not to be unreasonably withheld or delayed. 11.9 Denbury agrees to furnish Genesis, upon request, with copies of all electrical logs, core analyses, and completion reports relating to any well now or hereafter drilled upon the Subject Lands. Denbury agrees to furnish Genesis, upon request, with full information regarding the condition of the wells and the lease operations relating to the Subject Interests. The reasonable cost of copying any data and information described in this Section shall be paid by Genesis. Furthermore, Denbury's disclosure of the data and information described in this Section is subject to and may be limited by any confidentiality obligations or other restrictions to which Denbury may be subject. 11.10 In the event that any Lease or other interest that constitutes a part of the Subject Interests should expire or terminate for any reason (a "Lost Interest"), and within one (1) year from date of such expiration or termination of such Lost Interest, Denbury should reacquire such Lost Interest, then such Lost Interest shall be charged and burdened with the Production Payment to the same extent that the Lost Interest was charged and burdened with the Production Payment, and Denbury agrees to execute such documents and agreements as may be necessary or appropriate to effect the intent and purpose of this section. 11.11 Airgas Obligations. (a) Section 4.2 of the Airgas Contract provides that Airgas at no time will pay a price for CO(2) delivered under the terms of the Airgas Contract that is greater than the lowest price paid by any other customer of the Seller (as defined therein) or its affiliates receiving CO(2) from the Source Field (as such terms are defined in the Airgas Contract). Section 4.2 of the Airgas Contract is hereafter referred to as the "Favored Nations Clause." If at any time during the Term Denbury triggers the Favored Nations Clause, then Denbury agrees to (i) immediately notify Genesis of such sales and (ii) reimburse Genesis for the incremental reduction of proceeds received by Genesis under the Airgas Contract resulting from the payment of a reduced price by Airgas. If at any time and from time to time Airgas notifies Genesis that it is entitled to a lower price pursuant to the Favored Nations Clause (a "Reduced Price Notice"), Genesis will immediately furnish the Reduced Price Notice to Denbury. Genesis agrees not to take any action with respect to the Reduced Price Notice until Denbury has had an opportunity to review the matter described in the Reduced Price Notice and, if it deems appropriate, to contest such matter. (b) Section 11.4 of the Airgas Contract (the "RFR Provision") provides that Airgas shall have the right to exercise its rights under the Right of First Refusal and Option to Purchase Agreement (as defined therein) upon the occurrence of certain events. Each Party agrees to notify the other Party if it receives the notice provided in the RFR Provision or if it becomes aware that Airgas has failed to receive 75% of its daily requirements of CO(2) on more than 45 days in any rolling 12-month period (an "RFR Delivery Failure"). If Genesis is the cause of the RFR 18 Delivery Failure (for reasons other than force majeure (as defined in the Airgas Contract)), then for so long as Genesis allows such RFR Delivery Failure to continue, Denbury shall have the right to make direct deliveries to Airgas in satisfaction of the delivery requirements in the Airgas Contract and all volumes delivered by Denbury pursuant to this sentence shall reduce the Scheduled Delivery Volumes otherwise deliverable pursuant to the Production Payment and, furthermore, for purposes of the Term, the total aggregate volumes included in the Term shall be reduced by an amount equal to 200% of the volumes so delivered pursuant to this sentence. If Denbury is the cause of the RFR Delivery Failure (for reasons other than (i) force majeure (as defined in the Airgas Contract) or (ii) a lack of reserves or insufficient deliverability of reserves (provided such lack of reserves or insufficient deliverability of reserves is not the result of a failure of Denbury to comply with covenants set out in Article XI)), and Airgas exercises its purchase rights in accordance with the RFR Provision, then, in addition to any other remedies that may be available, the Parties shall use good faith efforts to reach an agreement with respect to the allocation of proceeds paid by Airgas and their application to the Production Payment after it exercises its rights under the RFR Provision, and if the Parties are unable to reach such agreement, then such matter shall be resolved in accordance with the arbitration provisions contained in Article XIV. (c) Notwithstanding anything herein to the contrary, without the prior written consent of the other Party hereto, no Party shall amend or otherwise modify any terms or provisions of the Right of First Refusal and Option to Purchase Agreement. 11.12 Denbury acknowledges that, pursuant to this Agreement and the Contracts Assignment, Genesis is acquiring all of Denbury's rights, interest and obligations in the Industrial Sale Contracts. Notwithstanding such acquisition, there are certain covenants and obligations under the Industrial Sale Contracts that must be satisfied by the owner or operator of the Subject Interests. Accordingly, Denbury covenants that, until the termination of each such Industrial Sale Contract and subject to the applicable force majeure provisions in the applicable Industrial Sale Contracts, it will fully and timely perform each and every covenant and agreement in each Industrial Sale Contract which must be performed by the Seller (as defined in each Industrial Sale Contract) and which relates to the ownership and operations of each Source Field, the production of carbon dioxide from each Source Field, and/or the measurement, metering, testing and other transportation services related thereto, including but not limited to the obligations and covenants in (a) Sections 2.5, 3.3, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1, 8.2 and 9.2 of the Airgas Contract; (b) Sections 2.5, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1 and 8.2 of the BOC-Brandon Contract; and (c) Sections 2.5, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1 and 8.2 of the Praxair Contract. The covenants and agreements of Denbury described in this section are collectively referred to herein as the "Retained Obligations". 11.13 Denbury shall not sell CO(2) to any Buyer (as such term is defined in each of the Industrial Sale Contracts), unless each Buyer has purchased from Genesis, pursuant to each of the Industrial Sale Contracts, the total Daily Contract Quantity and Additional Volumes (as such terms are defined in each of the Industrial Sale Contracts) under each Industrial Sale Contract; 19 provided, however, that notwithstanding the foregoing, Denbury shall be permitted to sell CO(2) to any such Buyers pursuant to and in accordance with the terms of the following contracts (and any amendments, replacements or renewals thereof that perpetuate only the rights and obligations currently existing under such contracts): (i) Contract for Sale of Carbon Dioxide Gas dated November ___, 1995 (presumed to be effective February 1, 1996), by and between Pennzoil Exploration and Production Company, as Seller, and Pisgah Partners, L.P., as Buyer; (ii) Contract for Sale of Carbon Dioxide Gas dated December 18, 2000, by and between Magna Carta Group LLC, as Seller, and Messer Greisheim Industries, Inc., as Buyer; and (iii) Carbon Dioxide Sale and Purchase Contract dated and effective February 1, 1996, by and between Shell Western E&P Inc., as Seller, and Liquid Carbonic Industries Corporation, as Buyer, as amended by Amendment No. 1 dated as of December 1, 1996, between Seller and Buyer. 11.14 For so long as the Industrial Sale Contracts are in force and effect, the Production Payment Gas delivered by Denbury to Genesis shall meet the minimum quality specification set forth in the Industrial Sale Contracts. XII. EXCHANGE OF INFORMATION; AUDIT RIGHTS 12.1 After Closing, (a) Denbury will keep Genesis advised of Denbury's activities in the fields encompassing the Subject Lands insofar as such activities relate to the terms and provisions of this Agreement, (b) each Party shall promptly give, or cause to be given to the other Party, written notice of any event or circumstance, including, but not limited to every adverse claim or demand made by any Person or any Governmental Authority, that could reasonably be expected to have a Material Adverse Effect, (c) each Party shall give or cause to be given to the other Party written notice of every default under any Industrial Sale Contract and every adverse claim or demand made by any Person or any Governmental Authority related to any Industrial Sale Contract, promptly upon obtaining knowledge of such default, claim or demand and shall include in such notice a description in reasonable detail of the default, claim or demand and if such Party obtained knowledge of such default, claim or demand as a result of the receipt of a written notice, a copy of such written notice, and (d) each Party shall also provide information to the other Party as needed to confirm compliance with each Party's obligations under this Agreement and the other Master Documents, to keep the other Party updated as to matters relating to this Agreement and the other Master Documents, from time to time, and in response to reasonable inquiries by the other Party. 12.2 After Closing, each Party, by notice in writing to the other Party, shall have the right to audit the other Party's accounts and records relating to the Production Payment, the Industrial Sale Contracts, and compliance with this Agreement and the other Master Documents. Audit rights pertaining to the T&P Agreement are subject to the terms and provisions with respect to auditing as set forth in the T&P Agreement. Audit rights otherwise pertaining to the Production Payment, the Industrial Sale Contracts, or other compliance issues under this Agreement and the other Master Documents are subject to the terms of Section 12.3. 12.3 Audits shall not be conducted more than twice each year without prior approval of the Party whose records are being audited (the "Audited Party"), and shall be made at the expense of the Party conducting the audit. The Audited Party shall reply in writing to an audit 20 report within thirty (30) days after receipt of such report. The Parties will endeavor to agree upon and make any adjustments revealed to be necessary by any audit reports submitted by the Audited Party pursuant to the provisions of this Section. If the Parties cannot agree on any adjustment, the disputed adjustment will not be made, and such disputed adjustment shall be resolved in accordance with the dispute resolution provisions described in Section 14.1. XIII. NOTICES 13.1 All notices under this Agreement must be in writing. Any notice with respect solely to the matters in the T&P Agreement shall be in accordance with the provisions pertaining to notices set forth in the T&P Agreement. Any other notice under this Agreement may be given by personal delivery, facsimile or email transmission, U.S. mail (postage prepaid), or commercial delivery service, and will be deemed duly given when received by the Party charged with such notice and addressed as follows: If to Denbury: Denbury Resources Inc. 5100 Tennyson Parkway, Suite 3000 Plano, TX 75024 Attn: Ray Dubuisson Telephone: 972-673-2044 Fax: 972-672-2299 email: rayd@denbury.com If to Genesis: Genesis Crude Oil, L.P. 500 Dallas, Suite 2500 Houston, TX 77002 Attn: Mark Gorman Telephone: (713) 860-2500 Fax: (713) 860-2640 email: mgorman@genesiscrudeoil.com 13.2 Either Party, by written notice to the other, may change the address or the individual to which or to whom notices are to be sent under this Agreement. XIV. DISPUTE RESOLUTION 14.1 Except as may be otherwise specifically provided herein, all disputes arising under or in connection with this Agreement shall be resolved in accordance with the procedures described in Exhibit E attached hereto and incorporated herein by reference for all purposes. XV. CURTAILMENTS AND INTERRUPTIONS 15.1 If Denbury is unable on any day, whether due to interrupted or curtailed service at the Jackson Dome Plant, lack of deliverability from the producing wells, or lack of capacity on 21 the Denbury Pipeline, or any other reason, to transport all volumes of CO(2) tendered for transportation through the Denbury Pipeline (inclusive of all volumes which Denbury may tender for transportation for its own account), and excluding those instances of inability to transport due to force majeure (in which cases the specific provisions as to force majeure in the Master Documents or in the relevant Industrial Sale Contracts will control), Denbury may interrupt or curtail service or receipt or delivery of CO(2), without liability to or penalty payable to Genesis, in a manner (i) so that volumes attributable to the Airgas Contract ("Airgas Volumes") are subject to curtailment only after complete curtailment of volumes attributable to all other parties, and then Airgas Volumes will be curtailed only as may be permitted under the Airgas Contract; (ii) so that the Excess Volumes and the volumes attributable to each of the BOC Contract and the Praxair Contract will be curtailed on a basis that is pro-rata to the volumes attributable to each of those contracts set forth in Schedule 5.18 and Denbury for its own account; provided that if the interruption or curtailment of service is longer than 45 consecutive days, then any volumes which Denbury tenders for transportation for its own account will not be included in the proration under clause (ii) above unless and until 100% of the Scheduled Delivery Volumes have been transported, determined in each case on a daily basis. In all circumstances above requiring curtailment, all pro-rations of volumes shall be proportionately based on the actual average volumes which have been transported during the 30 days before the interruption or curtailment of service occur. XVI. MISCELLANEOUS PROVISIONS 16.1 This Agreement and the other Master Documents constitute the entire understanding between the Parties relating to the subject matter hereof, and supersede all prior negotiations, discussions, agreements and understandings between the Parties, whether written or oral, regarding the subject matter of this Agreement. 16.2 This Agreement may be amended, modified, and supplemented only by written instrument executed by both Parties and explicitly referred to as an amendment to this Agreement. 16.3 The waiver by either Party of any breach of the provisions of this Agreement shall not constitute a continuing waiver of other breaches of the same or other provisions of this Agreement. 16.4 Neither Party shall be liable to the other for any special, indirect, consequential or punitive damages of any nature, or for attorneys' fees. 16.5 The interests of the Parties in this Agreement, and the interests acquired by virtue of this Agreement and the interests retained by Denbury in the Subject Lands, may not be subsequently assigned, either in whole or in part, unless (i) any such assignee expressly agrees in writing to assume and perform all of the assignor's obligations under this Agreement and the other Master Documents, and (ii) such assignment is made and accepted expressly subject and subordinate to this Agreement and the other Master Documents. Further, any subsequent assignment, either in whole or in part, to an entity that is not as financially creditworthy at the time of the assignment as the assignor shall require the consent of the other party hereto, which 22 consent may not be unreasonably withheld or delayed. Subject to the compliance with the terms of clauses (i) and (ii) above, either Party may encumber or pledge its respective interests in connection with a financing without the consent of the other Party. Any purported assignment, sale, conveyance or other transfer in contravention of the foregoing terms shall be null and void. Subject to the foregoing, this Agreement binds and inures to the benefit of the Parties and their respective permitted successors and assigns, and nothing contained in this Agreement, express or implied, is intended to confer upon any other person or entity any benefits, rights, or remedies. 16.6 If any provision of this Agreement is found by a court of competent jurisdiction to be invalid or unenforceable, that provision will be deemed modified to the extent necessary to make it valid and enforceable, and if it cannot be so modified, it shall be deemed deleted and the remainder of the Agreement shall continue and remain in full force and effect. 16.7 This Agreement shall be governed by and construed according to the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might apply the law of another jurisdiction. Venue for any arbitration, lawsuit or other legal action in any way pertaining to this Agreement or any other Master Document shall be in Dallas, Dallas County, Texas. 16.8 The Parties agree to do, execute, acknowledge and deliver all further acts, conveyances and instruments as may be reasonably necessary or appropriate to carry out the provisions of this Agreement. 16.9 The omission of certain provisions of this Agreement from the Assignment does not constitute a conflict or inconsistency between this Agreement and the Assignment, and will not effect a merger of the omitted provisions. To the fullest extent permitted by law, all provisions of this Agreement are hereby deemed incorporated into the Assignment by reference. The headings and titles in this Agreement are for convenience only and shall have no significance in interpreting or otherwise affect the meaning of this Agreement. 16.10 This Agreement may be executed in counterparts, each of which shall constitute an original and all of which shall constitute one document. 16.11 This Agreement may be circulated and executed by facsimile transmission, and in such event, the signatures of the Parties on facsimiles shall be considered as original and self-proving for all purposes. 16.12 Genesis and Denbury agree to treat the Subject Interest as a production payment under Section 636(a) of the Code. Both Genesis and Denbury agree (i) to file all federal income tax and state income tax returns consistent with this Section 16.12, and (ii) to use a comparable yield of 7.5% for purpose of Treasury Regulation Section 1.1275-4(b). 23 This Agreement is executed as of the date set out in the first paragraph of this Agreement, but shall be effective as of the Effective Date. DENBURY RESOURCES INC. By: /s/ Phil Rykhoek -------------------------------------- Phil Rykhoek Senior Vice President and Chief Financial Officer GENESIS CRUDE OIL, L.P. By: Genesis Energy, Inc. Its General Partner By: /s/ Mark J. Gorman ----------------------------------- Name: Mark J. Gorman Title: President 24 EX-10.8 4 h14014exv10w8.txt CARBON DIOXIDE TRANSP. AGREEMENT EXHIBIT 10.8 CARBON DIOXIDE TRANSPORTATION AGREEMENT BETWEEN DENBURY RESOURCES INC. AS "TRANSPORTER" AND GENESIS CRUDE OIL, L.P. AS "SHIPPER" CARBON DIOXIDE TRANSPORTATION AGREEMENT TABLE OF CONTENTS
Page ARTICLE I - DEFINITIONS ............................................... 1 1.1 Defined words and terms ...................................... 1 ARTICLE II - SCOPE OF TRANSPORTATION SERVICE .......................... 3 2.1 Transportation of Carbon Dioxide ............................. 3 2.2 Redelivery of Carbon Dioxide ................................. 3 2.3 Non-Exclusive Transportation ................................. 4 2.5 Operation of Transporter's Pipeline .......................... 4 2.6 Transporter's Processing Rights .............................. 4 2.7 Excess Quantities ............................................ 4 2.8 Call Option .................................................. 4 ARTICLE III - RATES AND CHARGES ....................................... 5 3.1 Initial Rate ................................................. 5 3.2 Adjusted Rate ................................................ 5 3.3 Minimum Rate ................................................. 5 3.4 Tax Reimbursement ............................................ 5 ARTICLE IV - TERM; EARLY TERMINATION FOR DEFAULT ...................... 6 4.1 Term ......................................................... 6 4.2 Default ...................................................... 6 4.3 Occurrence of Default ........................................ 6 ARTICLE V - RECEIPT POINTS, DELIVERY POINTS AND PRESSURES ............. 6 5.1 Receipt Points and Delivery Points ........................... 6 5.2 Responsibility ............................................... 7 5.3 Pressure Criteria ............................................ 7 ARTICLE VI - QUANTITY ................................................. 7 6.1 Delivery Rates ............................................... 7 6.2 Cooperation Regarding Deliveries ............................. 8 ARTICLE VII - QUALITY SPECIFICATIONS .................................. 8 7.1 Specification ................................................ 8 7.2 Testing ...................................................... 8 7.3 Failure to Meet .............................................. 8 ARTICLE VIII - OWNERSHIP AND OPERATION OF FACILITIES .................. 9 8.1 Facility Ownership ........................................... 9
i ARTICLE IX - MEASUREMENT .............................................. 9 9.1 Measurement Point ............................................ 9 9.2 Procedure .................................................... 9 9.3 Atmospheric Pressure ......................................... 9 9.4 Meter Standards .............................................. 9 9.5 Temperature .................................................. 9 9.6 Density ...................................................... 9 9.7 Samples ...................................................... 9 ARTICLE X - FORCE MAJEURE ............................................. 10 10.1 Definition ................................................... 10 10.2 Extended Force Majeure ....................................... 10 10.3 Strikes and Lockouts ......................................... 10 ARTICLE XI - NOTICES .................................................. 11 11.1 Transporter Notices .......................................... 11 11.2 Shipper Notices .............................................. 11 11.3 Change of Address ............................................ 11 ARTICLE XII - PAYMENT, AUDIT AND FINANCIAL RESPONSIBILITY ............. 11 12.1 Payment ...................................................... 11 12.2 Auditing ..................................................... 11 12.3 Failure to Pay ............................................... 12 12.4 Financial Responsibility ..................................... 12 ARTICLE XIII - WARRANTY ............................................... 12 13.1 Warranty ..................................................... 12 ARTICLE XIV - GENERAL TERMS AND CONDITIONS ............................ 12 14.1 Waiver of Breach ............................................. 13 14.2 Regulatory Bodies ............................................ 13 14.3 CHOICE OF LAW ................................................ 13 14.4 Joint Preparation ............................................ 13 14.5 Assignment ................................................... 13 14.6 Modification and Entire Agreement ............................ 13 14.7 Headings ..................................................... 13 14.8 Damage Limitation ............................................ 14 14.9 Arbitration .................................................. 14 14.10 Master Agreement; Conflicts .................................. 14
ii CARBON DIOXIDE TRANSPORTATION AGREEMENT THIS CARBON DIOXIDE TRANSPORTATION AGREEMENT (this "Agreement"), made and entered into effective as of September 1, 2003, by and between DENBURY RESOURCES INC., a Delaware corporation, hereinafter referred to as "Transporter", and GENESIS CRUDE OIL, L.P., a Delaware limited partnership, hereinafter referred to as "Shipper". WITNESSETH: WHEREAS, Shipper owns an interest in and/or has the right to market or otherwise control the disposition of Carbon Dioxide produced from certain wells located in the Jackson Dome area in Rankin County, Mississippi; and, WHEREAS, Transporter owns and operates a gathering system connected to a mainline pipeline extending approximately one hundred eighty-three miles from a point at the outlet flange of a Carbon Dioxide dehydration facility located in Rankin County near Jackson, Mississippi, to a point in White Castle, Ascension Parish, Louisiana, which currently is capable of delivering Carbon Dioxide to the various delivery points; and, WHEREAS, Transporter currently has available pipeline capacity for the transportation of Carbon Dioxide for Shipper; and, WHEREAS, Shipper desires to arrange for the transportation of Carbon Dioxide through Transporter's pipeline and Transporter desires to receive from, transport and redeliver to Shipper Carbon Dioxide in accordance with the terms and conditions stated in this Agreement. NOW, THEREFORE, for and in consideration of the mutual benefits to be derived, the terms and conditions contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Transporter and Shipper hereby agree with each other as follows: ARTICLE I DEFINITIONS 1.1 Defined words and terms. Except where the context otherwise indicates another or different meaning or intent, the following words and terms as used herein shall have the meanings indicated: (a) The term "Airgas Contract" has the meaning set out in the Master Agreement. (b) The term "Bankruptcy Event" means, with respect to either party, the entry of a decree or order by a court of competent jurisdiction adjudging the party a bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the party under the Federal Bankruptcy Code or any other applicable law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the party or of any substantial part of its property, or ordering the winding up or liquidation of its affairs, and the continuance of any such decree or order unstayed and in effect for a period of sixty (60) consecutive days; or the consent by such party to the institution of bankruptcy or insolvency proceedings against it, or the filing by it of a petition or answer or consent seeking reorganization or similar relief under the Federal Bankruptcy Code or any other applicable law, or the consent by it to the filing of any such petition or to the appointment of a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the party or of any substantial part of its property, or the making by it of an assignment for the benefit of creditors, or the admission by it in writing of its inability to pay its debts generally as they become due and its willingness to be adjudicated a bankrupt. (c) The terms "Carbon Dioxide" and "CO(2)" each mean a substance primarily composed of molecules containing one atom of carbon and two atoms of oxygen and containing at least 95 percent by volume of such molecules. (d) The term "Contract Year" means a period of three hundred sixty-five (365) consecutive days beginning on the first day of a full month following the month in which deliveries commence under this Agreement or on any anniversary thereof; provided, however, that any such year which contains a date of February 29th shall consist of three hundred sixty-six (366) consecutive days. This definition of Contract Year contemplates the possibility of first deliveries occurring on a day other than the first day of a month. (e) The term "cubic foot" is the amount of Carbon Dioxide necessary to fill one cubic foot of space at a base pressure of 15.025 psia and at a base temperature of 60 degrees Fahrenheit. (f) The term "Daily Maximum Quantity" has the meaning set out in the Master Agreement. (g) The term "day" means a period beginning at 7:00 a.m. (local time) on a calendar day and ending at 7:00 a.m. (local time) on the next succeeding calendar day. The date of a day shall be that of its beginning. (h) The term "Delivery Points" has the meaning stated in Section 2.2. (i) The term "Industrial Sale Contracts" has the meaning set out in the Master Agreement. (j) The term "Jackson Dome Plant" means the Jackson Dome Processing Plant owned by Denbury located in Brandon, Rankin County, Mississippi. 2 (k) The term "Master Agreement" means that certain Production Payment Purchase and Sale Agreement executed contemporaneously herewith by Transporter and Shipper. (l) The term "Master Documents" means the Master Agreement and all agreements executed in connection therewith or pursuant thereto, including but not limited to this Agreement. (m) The term "MCF" means 1,000 cubic feet of Carbon Dioxide. (n) The term "MMCF" means 1,000,000 cubic feet of Carbon Dioxide. (o) The term "month" means a period beginning on the first day of a calendar month and ending at the beginning of the first day of the next succeeding calendar month. (p) The term "pound-mass" means the mass quantity of Carbon Dioxide equivalent to a pound-mass as defined by the United States National Bureau of Standards. (q) The term "Production Payment" has the meaning set out in the Master Agreement. (r) The term "psia" means pounds per square inch absolute. (s) The term "psig" means pounds per square inch gauge. (t) The term "Receipt Points" has the meaning stated in Section 2.1. (u) The term "Transportation Fee" has the meaning stated in Article III. (v) The term "Transporter's Pipeline" means Transporter's existing gathering system and pipeline used for the gathering, dehydration and transportation of Carbon Dioxide from wells owned or controlled by Transporter in Rankin County, Mississippi, which gathering system extends from various wellheads owned or controlled by Transporter to a point at the outlet flange of a Carbon Dioxide dehydration facility located in Rankin County, Mississippi, and which pipeline extends from that point to a point in Ascension Parish, Louisiana. ARTICLE II SCOPE OF TRANSPORTATION SERVICE 2.1 Transportation of Carbon Dioxide. Subject to all of the terms, conditions, and limitations of this Agreement, each day during the term hereof Shipper shall have the right to tender to Transporter at the Receipt Points set forth in Exhibit A (the "Receipt Points") for transportation hereunder any volume of Carbon Dioxide up to the Daily Maximum Quantity. 2.2 Redelivery of Carbon Dioxide. Subject to all of the terms, conditions, and limitations of this Agreement, each day during the term hereof Transporter shall redeliver to 3 Shipper, at the Delivery Points set forth in Exhibit B (the "Delivery Points"), the volume of Carbon Dioxide delivered by Shipper to Transporter at the Receipt Points on such day, as such volumes may be adjusted for Shipper's proportionate share of reductions due to Carbon Dioxide lost and unaccounted for in Transporter's Pipeline and any other loss or shrinkage factor generally applicable from time to time to Transporter's Pipeline. 2.3 Non-Exclusive Transportation. Subject to the qualification as to priority set out in Section 2.4, nothing in this Agreement shall be construed to prohibit Transporter from transporting Carbon Dioxide for a person or persons other than Shipper. Nothing in this Agreement shall be construed to require Shipper to tender any minimum quantity of Carbon Dioxide to Transporter for transportation hereunder. 2.4 INTENTIONALLY DELETED. 2.5 Operation of Transporter's Pipeline. Except as otherwise provided in Section 2.8, Transporter will at all times maintain, preserve and keep all improvements, machinery, equipment, pipe lines, tanks, fixtures and other personal property and equipment of every kind and nature now or hereafter required in connection with operation of Transporter's Pipeline in good repair, working order and condition, and promptly make all necessary and proper repairs, renewals, replacements and substitutions. Subject to the forgoing and its other obligations hereunder, Transporter may, at its sole discretion, at any time and from time to time, expand, extend, repair, reconfigure or temporarily shutdown Transporter's Pipeline and related equipment. In exercising the foregoing rights, Transporter shall have no liability to Shipper hereunder and shall use all reasonable efforts to minimize any adverse impact on Shipper's rights hereunder. 2.6 Transporter's Processing Rights. Transporter reserves the right, prior to delivery to Shipper at the Delivery Points set forth herein, at the sole cost of Transporter, to process and/or treat Carbon Dioxide received from Shipper hereunder for any purpose; provided, however, subject to Section 7.3, Carbon Dioxide delivered to the Delivery Points shall meet the quality specifications of Article VII hereof. 2.7 Excess Quantities. Shipper may, on any day and upon prior notice to Transporter, tender at the Receipt Point volumes of Carbon Dioxide in excess of the Daily Maximum Quantity, in which event Transporter may, in its sole judgment, transport all or any portion of such excess volumes on a fully interruptible basis. However, the transportation of any excess volumes by Transporter shall otherwise be subject to all of the terms and provisions hereof. 2.8 Call Option. In the event a Triggering Event (as hereinafter defined) occurs, Transporter shall have the right and option to either (i) repair, replace, restore and reconstruct Transporter's Pipeline in substantially the form in which the same existed prior to any such Triggering Event or (ii) exercise (or cause the exercise of) the Call Option provided for in Section 2.4 of the Master Agreement. Transporter shall notify Shipper in writing of its election of one of the options set forth above within thirty (30) days from the date of the Triggering Event. If Transporter elects the option set out in clause (i) above, then Transporter shall commence the restoration work within thirty (30) days from the date of the Triggering Event and 4 diligently prosecute and complete the restoration work within a reasonable time, in no event exceeding twelve (12) months from the date of the Triggering Event. If Transporter elects the option set forth in clause (ii) above, the Call Option set forth in Section 2.4 of the Master Agreement shall be exercised in accordance with the terms thereof. If Transporter fails to notify Shipper of its election of either clause (i) or (ii) above within thirty (30) days from the date of the Triggering Event, Transporter shall, as of such date, be deemed to have delivered notice to Shipper electing to exercise the option set forth in clause (i) above. For purposes hereof, a "Triggering Event" means (a) the entire or partial destruction or damage of Transporter's Pipeline by fire or any other casualty whatsoever; or (b) a mechanic failure or other breakdown of Transporter's Pipeline, which in either case actually renders Transporter's Pipeline inoperable for a minimum period of ninety-five (95) consecutive days. ARTICLE III RATES AND CHARGES 3.1 Initial Rate. For the transportation and dehydration of each MCF of Shipper's Carbon Dioxide received at the Receipt Points during any month, beginning with the date of first deliveries hereunder and continuing through the end of the first Contract Year, Shipper shall pay Transporter a transportation fee (the "Transportation Fee"), which fee shall initially be $0.16 (the "initial rate"). 3.2 Adjusted Rate. Effective on the first day of each Contract Year after the first Contract Year, the Transportation Fee shall be adjusted, upward or downward. Computations to determine such adjustments shall be made utilizing $0.16/Mcf as the base rate. The adjustment shall be based upon the change in the annual average of the Producers Price Index, "PPI," All Commodities, 1982 = 100, as published by the United States Department of Labor, Bureau of Labor Statistics. To determine the adjusted rate for each subsequent Contract Year, the following formula shall be used: Adjusted rate = Base rate x (0.10 + 0.90 x PPI current/PPI base) or the initial rate, whichever is greater. Thus, by way of illustration, should the average PPI for the year 2002 be 125, and the average PPI for the year 2003 be 130, the adjusted price for the subsequent Contract Year, 2004, commencing on the anniversary of the Contract Year, would be computed as follows: $0.16 x (0.10 + 0.90 x 130/125) = $0.16576 3.3 Minimum Rate. Notwithstanding the foregoing, the Transportation Fee, as adjusted herein, shall never be less than $0.16 per MCF. 3.4 Tax Reimbursement. In addition to the Transportation Fee provided for above, Shipper shall reimburse Transporter for all taxes which are levied upon and/or paid by Transporter with respect to the services performed under this Agreement, but only if and to the extent that Shipper has the right to receive reimbursement for such taxes from Shipper's customers under the terms of Shipper's resale contracts with its customers. 5 ARTICLE IV TERM; EARLY TERMINATION FOR DEFAULT 4.1 Term. Subject to the other provisions hereof, this Agreement shall be effective from the date hereof and shall continue in force and effect until the Production Payment is fully discharged. 4.2 Default. The occurrence of one or more of the following matters shall constitute a default by a party: (a) the occurrence of a Bankruptcy Event involving such party; (b) the failure of such party to make any payment to the other party as and when due hereunder where such failure continues for thirty (30) days after the delivery of written notice by the other party of such failure to make such payment; and, (c) the breach by such party of any other material covenant, agreement, obligation, duty or provision of this Agreement, where such breach continues for thirty (30) days after its receipt of written notice thereof from the other party; provided, however, that if the matter which is the subject of the breach cannot by its nature with due diligence be remedied by such within said thirty (30) day period, and such party shall have prepared a plan for remedying such failure that is reasonably acceptable to the other party and such party is proceeding with diligence to implement such plan, such thirty (30) day period shall be extended by such additional time period as may be reasonably required to implement such plan, and, provided further, however, that the remedying of such potential default shall not affect the right of the other party to terminate this Agreement if other defaults occur before such potential default has been remedied. 4.3 Occurrence of Default. Upon the occurrence of a default by a party, the other party may exercise any right or remedy it may have at law and/or in equity; provided that Transporter shall not be entitled to terminate this Agreement. If pursuant to an arbitration proceeding conducted in accordance with Section 14.9, it is determined that as a result of a Shipper default Transporter has suffered a specified amount of damages, the arbitrators may provided as a remedy to Transporter that Transporter may sell a portion of Shipper's carbon dioxide necessary to generate sufficient proceeds to reimburse Transporter for such damages. ARTICLE V RECEIPT POINTS, DELIVERY POINTS AND PRESSURES 5.1 Receipt Points and Delivery Points. The Receipt Points are set forth on Exhibit A. The Delivery Points are set forth on Exhibit B. Shipper may request at any time and from time to time that Transporter agree to one or more additional Receipt Points or Delivery Points on Transporter's Pipeline. Transporter shall not unreasonably withhold its agreement to the addition of any additional Receipt Point or Delivery Point requested by Shipper as long as Shipper reimburses Transporter for all incremental costs incurred or to be incurred by 6 Transporter as a result of the addition of such Receipt Point or Delivery Point and, with respect to requested Receipt Points only, so long as Transporter owns or controls the well or wells to be producing into the requested Receipt Point. If Transporter's estimated incremental cost to establish an additional Receipt Point or Delivery Point requested by Shipper exceeds $25,000, then Transporter shall be entitled to require that Shipper pay Transporter such estimated incremental cost before agreeing to add such additional Receipt Point or Delivery Point, with a "true-up" payment being made by the appropriate party to the other party when the final, actual incremental costs of such additional Receipt Point or Delivery Point are known. Upon the addition of any Receipt Point or Delivery Point, the parties shall execute an amendment of this Agreement which shall reflect all of the Receipt Points or Delivery Points on a revised Exhibit A or Exhibit B, as appropriate. The exact point at which delivery by Transporter to Shipper shall be deemed to be made shall be the flange or weld connecting the facilities of Transporter's Pipeline with the facilities of Shipper or Shipper's designee. 5.2 Responsibility. As between the parties hereto, and subject to the limitations set forth in other provisions of this Agreement, Transporter shall be responsible for any injuries, losses, expenses, claims, liabilities, or damages caused by the Carbon Dioxide while it is in Transporter's Pipeline until it shall have been delivered to Shipper or Shipper's designee at the Delivery Points, and, after such delivery, Shipper shall be responsible for any injuries, losses, expenses, claims, liabilities, or damages caused thereby. Subject to the limitations set forth in other provisions of this Agreement, each party (the "Indemnifying Party") shall indemnify the other party in respect of any injuries, losses, expenses, claims, liabilities, or damages occurring while the Carbon Dioxide is in possession of the Indemnifying Party. Transporter shall not take title to Shipper's Carbon Dioxide in Transporter's Pipeline merely by receipt of such Carbon Dioxide for Shipper's account 5.3 Pressure Criteria. All Carbon Dioxide tendered by Shipper at any Receipt Point shall be delivered at pressures sufficient to enter Transporter's Pipeline at the working pressures maintained by Transporter at such Receipt Point from time to time. Transporter shall deliver the volumes of Carbon Dioxide as provided for hereunder at the Delivery Points at pressures ranging from 1100 to 1400 psig. Notwithstanding the foregoing, Transporter reserves the right at any time and from time to time, to revise the maximum and/or the minimum pressures set forth above on ten (10) days' prior notice to Shipper to the extent the implementation of any such revision is prudent in light of the operating conditions on the Transporter's Pipeline. ARTICLE VI QUANTITY 6.1 Delivery Rates. Transporter and Shipper shall endeavor to deliver and to accept, respectively, Carbon Dioxide in as reasonable constant rates as is practicable. Transporter and Shipper understand and agree that the amount of Carbon Dioxide delivered hereunder from time to time may not exactly equate with the volume of Carbon Dioxide requested for delivery hereunder since variations may occur due to the inherent fluctuations in normal pipeline operations. Upon request from Shipper, Transporter may deliver Carbon Dioxide on any day in excess of the Daily Maximum Quantity, but Transporter shall not be obligated to do so. 7 6.2 Cooperation Regarding Deliveries. Shipper or Shipper's agent shall notify Transporter monthly, in advance, of Shipper's estimated daily requirements at each of the Receipt Points and the Delivery Points for the next succeeding month and Transporter shall deliver such requirements, up to the Daily Maximum Quantity, out of the volumes received by Transporter at the Receipt Points for Shipper's account. Transporter and to the extent it will not result in a default under a Industrial Sale Contract, Shipper agree to fully cooperate with each other in adjusting monthly and daily deliveries hereunder. Shipper or Shipper's agent shall give twenty-four (24) hours' prior notice of any additional changes in its daily requirements as may be necessary from time to time and, on receipt of such notice by Shipper, Transporter shall undertake as soon as practicable to conform its deliveries to Shipper's revised daily requirements (up to the Daily Maximum Quantity) and shall notify Shipper as soon as practicable if Transporter is unable to do so. In the event of an emergency which poses danger to life or property, no prior notice shall be necessary before partial or total shutdown by either party, but notice of such shutdown and the reason therefor shall be given as soon as practicable thereafter. If a shutdown becomes necessary for either party on a non-emergency basis, such party shall give at least twenty-four (24) hours' prior notice to the other party. ARTICLE VII QUALITY SPECIFICATIONS 7.1 Specification. The Carbon Dioxide delivered by Transporter to Shipper at the Delivery Points shall meet the following specifications (collectively the "Quality Specification"): (a) Water. The Carbon Dioxide shall not contain any free water and the water vapor content shall not exceed thirty (30) pounds per MMcf. (b) Hydrogen sulfide and sulfur. The Carbon Dioxide shall not contain more than 10 parts by weight of hydrogen sulphide nor more than 35 parts by weight of total sulfur per 1,000,000 parts of Carbon Dioxide. (c) CO(2) Volume. The Carbon Dioxide shall be 95% pure (dry basis). 7.2 Testing. Transporter shall ensure that tests to determine the quality of Carbon Dioxide are conducted as often as necessary in Transporter's sole opinion, utilizing approved standard methods in general use. Transporter may furnish Shipper with copies of all test results. Transporter shall give Shipper reasonable notice of all such tests in order that Shipper or Shipper's agent may have its representative present, if Shipper so desires. 7.3 Disclaimer. THE PARTIES HERETO RECOGNIZE AND AGREE THAT TRANSPORTER IS NOT A MERCHANT OF FOOD GRADE OR MERCHANTABLE CARBON DIOXIDE FOR USE IN FOOD OR DRINK OR OTHER CONSUMABLES AND TRANSPORTER IN NO WAY WARRANTS THE MERCHANTABILITY OR FITNESS OF ANY CARBON DIOXIDE DELIVERED OR TO BE DELIVERED HEREUNDER FOR ANY PARTICULAR PURPOSE. 8 ARTICLE VIII OWNERSHIP AND OPERATION OF FACILITIES 8.1 Facility Ownership. Transporter will own, operate and maintain the Transporter's Pipeline, and the pipelines and measurement facilities, including any additional equipment installed by or at the request of Shipper, at each Receipt Point and at each Delivery Point. Transporter will maintain Carbon Dioxide custody to the upstream flange of Shipper's valve on the outlet side of Transporter's measurement facilities at each Delivery Point. Transporter shall be solely responsible for the delivery of Carbon Dioxide to the inlet side of Shipper's tap valve at each Delivery Point. All piping downstream from the Delivery Points shall be the responsibility of Shipper. ARTICLE IX MEASUREMENT 9.1 Measurement Point. The Carbon Dioxide delivered hereunder shall be measured for custody transfer at the Delivery Points in accordance with the standards set out in this Article. 9.2 Procedure. Custody transfer measurement of Carbon Dioxide shall be determined from pound-mass quantities, which will be converted to standard cubic feet quantities. The molecular weight of the metered stream of Carbon Dioxide, calculated from the compositional analyses, shall be the basis for conversion of pound-mass measurement units to standard cubic feet measurement units. 9.3 Atmospheric Pressure. The atmospheric pressure at the Delivery Point shall be based upon 14.73 psia at sea level, corrected to actual elevation, and may be assumed to be constant for calculation purposes. 9.4 Meter Standards. The Carbon Dioxide delivered hereunder shall be measured with orifice meters constructed and installed in accordance with the October, 1981, compilation of standards in the American Petroleum Institute, Manual of Petroleum Standards, Chapter 14, with any subsequent amendments, revisions and additions which may be mutually acceptable to Transporter and Shipper. Computations of pound mass shall also be made in accordance with said manual. 9.5 Temperature. The temperature of the Carbon Dioxide shall be determined by an on-line temperature measuring device so installed that it will sense the temperature of the Carbon Dioxide flowing through the meter. 9.6 Density. The density of the Carbon Dioxide shall be determined by an on-line density meter referenced to weight in a vacuum, or by calculation utilizing the pressure, temperature and composition of the Carbon Dioxide flowing through the meter. 9.7 Samples. A composite sample of Transporter's Pipeline Carbon Dioxide stream shall be accumulated during each month and analyzed for its composition by gas chromatograph or other methods agreed to by Transporter and Shipper, at Transporter's expense. 9 ARTICLE X FORCE MAJEURE 10.1 Definition. If, while this Agreement is in effect, either party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations (except financial obligations) under this Agreement, it is agreed that, on such party's giving notice and reasonably full particulars of such Force Majeure in writing to the other party within ten (10) business days after the occurrence of the Force Majeure relied on, then the obligations of the party giving such notice, so far as they are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused, but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch. The term "Force Majeure", as used herein, shall mean acts of God, strikes, lockouts or other industrial disturbances, acts of the public enemy, wars, terrorism, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, high water, washouts, arrests and restraints of government and people, civil disturbances, explosions, breakage or accident to machinery or lines of pipe, freezing of wells or lines of pipe, partial or entire failure of wells, and any other causes, whether of the kind herein enumerated or otherwise, not reasonably within the control of the party claiming Force Majeure. Without limiting the generality of the foregoing, the term "Force Majeure" shall likewise include (a) in those instances where either party hereto is required to obtain servitudes, rights-of-way grants, permits or licenses to enable such party to perform hereunder, the inability of such party to acquire, or the delays on the part of such party in acquiring, at reasonable cost and after the exercise of reasonable diligence, such servitudes, rights-of-way grants, permits or licenses, and (b) in those instances where either party hereto is required to furnish materials and supplies for the purpose of constructing or maintaining facilities or is required to secure permits or permissions from any governmental agency to enable such party to perform hereunder, the inability of such party to acquire, or the delays on the part of such party in acquiring, at reasonable cost and after the exercise of reasonable diligence, such materials and supplies, permits and permissions. An occurrence of Force Majeure affecting Transporter's supply sources or processing facilities or gathering system or Transporter's Pipeline shall be deemed to be an occurrence of Force Majeure affecting Transporter hereunder. 10.2 Extended Force Majeure. If, after deliveries have commenced hereunder, an event of Force Majeure significantly affects the amount of Carbon Dioxide Transporter is capable of delivering for a consecutive period of 180 days, then, at any time after such period and prior to the time such event has been remedied, Shipper may cancel this Agreement. 10.3 Strikes and Lockouts. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty and that the above requirement that any Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of any opposing party when such course is inadvisable in the discretion of the party having the difficulty. 10 ARTICLE XI NOTICES 11.1 Transporter Notices. All notices provided for herein shall be in writing and shall be deemed to be delivered to Transporter when deposited in the United States mail to the following address: DENBURY RESOURCES INC. Attn: Linda A. Miller 5100 Tennyson Parkway Suite 3000 Plano, Texas 75024 11.2 Shipper Notices. All notices provided for herein shall be in writing and shall be deemed to be delivered to Shipper when deposited in the United States mail to the following address: GENESIS CRUDE OIL, L.P. Attn: Mark J. Gorman 500 Dallas St. Suite 2500 Houston, Texas 77002 11.3 Change of Address. Either party may change its address described in this Article by sending written notice to the other party in accordance with the provisions of this Article. ARTICLE XII PAYMENT, AUDIT AND FINANCIAL RESPONSIBILITY 12.1 Payment. Transporter shall furnish Shipper a monthly statement showing (i) the total quantity of Carbon Dioxide received hereunder during the preceding month at each Receipt Point, (ii) the total quantity of Carbon Dioxide delivered hereunder during the preceding month at each Delivery Point, and (iii) the incremental costs incurred by Transporter to add any additional Delivery Points requested by Shipper. Shipper shall make payment by wire transfer to such address as Transporter may designate from time to time on or before the later to occur of (x) the tenth day following the day that Transporter's monthly statement was delivered or (y) the twentieth day of the month following the month that Carbon Dioxide was delivered, such wire transfer being for all amounts payable hereunder. 12.2 Auditing. Each party shall have the right at reasonable business hours to examine the books, records, and measurement documents of the other party to the extent necessary to verify the accuracy of any statement, payment, calculation, or determination made pursuant to the provisions of this Agreement for any Contract Year within two (2) Contract Years following the end of such Contract Year. If any such examination shall reveal, or if either party shall discover, any error or inaccuracy in its own or the other party's statement, payment, calculation, or determination, then proper adjustment and correction thereof shall be made as promptly as practicable thereafter, except that no adjustment or correction shall be made for an error or 11 inaccuracy if more than two (2) Contract Years have elapsed since the end of the Contract Year in which such error or inaccuracy occurred. 12.3 Failure to Pay. If Shipper fails to pay any amount payable to Transporter hereunder when due, interest thereon shall accrue and be payable at the lesser of (i) the highest legally permissible rate or (ii) the prime lending rate, plus an additional five percent (5%), established by the Chase Manhattan Bank, N.A., New York, from the date when payment was due until the date payment is made. If such failure to pay any amount continues for thirty (30) days or more after the due date of such amount for any reason, then (a) Transporter may suspend its deliveries of Carbon Dioxide hereunder, (b) Transporter shall have the right to make direct deliveries in satisfaction of the delivery requirements in the Industrial Sale Contracts, and (c) such matter shall be resolved in accordance with the arbitration provisions described in Section 14.9. 12.4 Financial Responsibility. Notwithstanding anything to the contrary in this Agreement, should Transporter reasonably believe it necessary to assure payment for transportation of Carbon Dioxide being delivered or to be delivered hereunder, Transporter may at any time, require (i) advance cash payment; (ii) a standby irrevocable letter of credit at Shipper's expense in a form and from a bank acceptable to Transporter, in Transporter's sole opinion; or (iii) other security of a type and form and amount which may be deemed reasonably satisfactory to Transporter. In the event banking or credit information requested by Transporter has not been furnished within a reasonable time in Transporter's sole opinion, Transporter shall have the right, with five (5) days' prior notice, to withhold and/or suspend deliveries hereunder, in addition to any and all other remedies available hereunder; provided that Transporter shall not have the right to terminate this Agreement. ARTICLE XIII WARRANTY 13.1 Warranty. Each party warrants, for itself, its successors, heirs, legal representatives and assigns, to the other party that at the time such party delivers Carbon Dioxide to the other party, such party will have good title to or the good right to deliver such Carbon Dioxide, and that such Carbon Dioxide shall be free and clear from liens, encumbrances and claims of every kind. Each party shall indemnify and save the other party harmless from all suits, claims, liens, damages, costs, losses, expenses and encumbrances of whatsoever nature arising from and out of claims of any or all persons to said Carbon Dioxide, or title thereto, or to royalties, taxes, license fees, payments or other charges thereon applicable before the delivery of the Carbon Dioxide by such party to the other party. ARTICLE XIV GENERAL TERMS AND CONDITIONS 14.1 Waiver of Breach. The waiver by any party of any breach of the provisions of this Agreement shall not constitute a continuing waiver of other breaches of the same or other provisions of this Agreement. 12 14.2 Regulatory Bodies. This Agreement, all operations contemplated hereunder and all terms and provisions contained herein, and the respective obligations of the parties are subject to applicable federal and state laws and the applicable orders, rules, and regulations of any state or federal regulatory authority having appropriate jurisdiction. However, nothing contained herein shall be construed as a waiver of any right of any party to question or contest any such law, order, rule, or regulation in any forum having or alleging to have jurisdiction. Shipper and Transporter each agree to comply with all applicable laws and regulations governing the operations and transactions involved in this Agreement, including, but not limited to, applicable regulations governing safety, pollution, and pipeline and other operations. Transporter and Shipper understand that Shipper's ability to deliver Carbon Dioxide hereunder is subject to existing and future governmental regulations affecting Transporter's Pipeline. 14.3 CHOICE OF LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF MISSISSIPPI, EXCLUDING ITS CONFLICTS OF LAW PROVISIONS. 14.4 Joint Preparation. This Agreement was prepared by all parties hereto and not by any party to the exclusion of one or the other. 14.5 Assignment. The interests of the parties in this Agreement, and Transporter's interest in the Transporter's Pipeline, may not be subsequently assigned, either in whole or in part, unless (i) any such assignee expressly agrees in writing to assume and perform all of the assignor's obligations under this Agreement, and (ii) such assignment is made and accepted expressly subject and subordinate to this Agreement. Further, any subsequent assignment, either in whole or in part, to an entity that is not as financially creditworthy at the time of the assignment as the assignor shall require the consent of the other party hereto, which consent may not be unreasonably withheld or delayed. Subject to the compliance with the terms of clauses (i) and (ii) above, either party may encumber or pledge their respective interests in connection with a financing without the consent of the other party. Any purported assignment, sale, conveyance or other transfer in contravention of the foregoing terms shall be null and void. Subject to the foregoing, this Agreement binds and inures to the benefit of the parties and their respective permitted successors and assigns, and nothing contained in this Agreement, express or implied, is intended to confer upon any other person or entity any benefits, rights, or remedies. 14.6 Modification and Entire Agreement. No amendment or other modification of the terms or provisions of this Agreement shall be made except by the execution of written agreements by both parties, and any attempted modification or amendment not in compliance with the terms of this sentence shall be void ab initio. This Agreement and the other Master Documents contain the entire agreement between the parties with respect to the subject matter hereof, and supersede and terminate all prior negotiations, representations or agreements, whether written or oral, by and between the parties with respect to such subject matter 14.7 Headings. The Table of Contents and headings contained in this Agreement are used solely for convenience and do not constitute a part of the agreement between the parties hereto, and they should not be used to aid in any manner in construing this Agreement. 13 14.8 Damage Limitation. Neither party shall be liable to the other for any special, indirect, consequential or punitive damages of any nature. 14.9 Arbitration. In the event of a dispute between the parties as to any matter arising under this Agreement, such dispute shall be resolved in accordance with the dispute resolution provisions identified in Article XIV of the Master Agreement. 14.10 Master Agreement; Conflicts. This Agreement is delivered pursuant to and as a part of the transactions under the Master Agreement and is made expressly subject thereto. In the event of any express conflict between the terms and provisions of this Agreement and the terms and provisions of the Master Agreement, the terms and provisions of this Agreement shall control. The inclusion in the Master Agreement of provisions not addressed in this Agreement shall not be deemed a conflict, and all such additional provisions contained in the Master Agreement (including but not limited to Section 15.1 thereof) shall be given full force and effect. 14 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed in multiple originals by their proper officers thereunto duly authorized, as of the date first hereinabove written. TRANSPORTER DENBURY RESOURCES INC. By: /s/ Phil Rykhoek ----------------------------- Phil Rykhoek Senior Vice President and Chief Financial Officer SHIPPER GENESIS CRUDE OIL, L.P. By: /s/ Mark J. Gorman ----------------------------- Mark J. Gorman President 15 EXHIBIT "A" TO CARBON DIOXIDE TRANSPORTATION AGREEMENT BETWEEN DENBURY RESOURCES INC. AND GENESIS CRUDE OIL, L.P. DATED EFFECTIVE AS OF SEPTEMBER 1, 2003 RECEIPT POINT LOCATIONS AND DAILY MAXIMUM QUANTITY Daily Maximum Quantity: The Daily Maximum Quantity shall be the amount specified for such term in the Master Agreement.
Daily Maximum Quantity at this Receipt Receipt Point Description Point (if applicable) - ------------------------- -------------------------------------- 1. AirGas 22,500 Mcf/d 217 Andrew Jackson Circle Star, Mississippi 39167 2. Praxair 8,750 Mcf/d 214 Carbonic Dr. Brandon, Mississippi 39042 3. BOC 17,500 Mcf/d 159 Andrew Chapel Rd. Brandon, Mississippi 39042
EXHIBIT "B" TO CARBON DIOXIDE TRANSPORTATION AGREEMENT BETWEEN DENBURY RESOURCES INC. AND GENESIS CRUDE OIL, L.P. DATED EFFECTIVE AS OF SEPTEMBER 1, 2003 DELIVERY POINT LOCATIONS
Daily Maximum Quantity at this Delivery Delivery Point Description Point (if applicable) - -------------------------- --------------------------------------- Wells and wellhead meter numbers: McKay #2 FQI 300 McKay #1 (not flowing) FQI 301 Hauburg #4 FQI 302 Hauburg #3 FQI 303 Hauburg #1 FQI 304 Hauburg #2 FQI 305 Hauburg #6 FQI 306 Hauburg #5 FQI 307 Cruthirds #1 FQI 309 Denkmann FQI 310 International Paper (IP) FQI 311 Barksdale FQI 312
EX-10.9 5 h14014exv10w9.txt GENESIS ENERGY, INC. STOCK APPRECIATION RIGHTS PL. EXHIBIT 10.9 GENESIS ENERGY, INC. STOCK APPRECIATION RIGHTS PLAN SECTION 1 PURPOSE The purpose of the Stock Appreciation Rights Plan (the "Plan") is to advance the interests of Genesis Energy, Inc. (the "Company") and its affiliates and owners by providing performance incentives to employees and Directors of the Company whose present and potential contributions are important to the continued success of the Company. The Plan is intended to enable the Company to attract and retain highly qualified persons for the successful conduct of its business. These objectives are intended to be effected by creating a sense of equity participation in the Company through the sharing of the appreciation in the unit price of Genesis Energy, L.P.("GEL") Common Units. Definitions for certain terms are contained in Section 14 below. SECTION 2 ELIGIBILITY In order to be eligible for and receive an allocation of Units granted under Section 4 below for a Plan Year, the Participant must be a regular, full-time active employee, not on probation, or a Director of the Company on the date of the allocation of Units. SECTION 3 ADMINISTRATION OF THE PLAN The Plan shall be administered by the Compensation Committee of the Board of Directors of the Company (hereinafter referred to as the "Committee"). The Committee shall have full discretion and authority to administer the Plan. Any interpretation by the Committee of the terms and conditions of the Plan shall be final. The Plan shall be operated on a calendar year. SECTION 4 STOCK APPRECIATION RIGHTS (a) Stock Appreciation Rights (the "Units") will be allocated to the accounts (the "Accounts") of the Plan participants (the "Participants") in a manner determined by the Committee in its full discretion. (b) The total number of Units authorized for allocation to the Participants in the Plan each year shall be determined by the Committee in its full discretion. (c) For each year, the Committee shall determine, in its full discretion, the grant date for the allocation of Units among the eligible Participants in the Plan. (d) The Committee shall determine, in its full discretion, a prescribed formula for allocating Units to new employees of the Company. (d) Each Unit shall have a term of 10 years (i.e., 120 months) from the grant date. (e) At the time a Unit is allocated to each Participant, the Committee will assign a strike price to the Unit, referenced to the market price of GEL units at that time, as determined by the Committee in its full discretion. SECTION 5 VESTING AND FORFEITURE Each Participant will have a vested percentage of the Units allocated to that Participant's Account determined as follows: 2003 Grant: The Units allocated in 2003 and Units allocated to new employees pursuant to Section 4(d) will vest 25 percent per year for each full year of service from January 1, 2004. Therefore, each Participant receiving an allocation of Units for 2003 will become 100 percent fully vested in such Units if such Participant remains in continuous full-time employment with the Company through December 31, 2007. This can be summarized as follows:
Continuous Full-Time Employment Through Vested Percentage --------------------------------------- ----------------- December 31, 2004 25% December 31, 2005 50% December 31, 2006 75% December 31, 2007 100%
2004 and Later Grants: The Units allocated in 2004 and each year thereafter will remain unvested for the first three years and then become 100 percent fully vested to a Participant, if such Participant remains in continuous full-time employment with the Company through December 31 of the fourth calendar year following the year of allocation. In the case of the 2004 allocated Units, a qualified Participant will become fully vested on December 31, 2008. This can be summarized as follows:
Continuous Full-Time Employment Through Vested Percentage --------------------------------------- ----------------- December 31, 2005 0% December 31, 2006 0% December 31, 2007 0% December 31, 2008 100%
2 If a Participant terminates employment for any reason other than death, Disability or Normal Retirement, the Participant will forfeit the nonvested Units in his or her Account. Units forfeited in a Plan Year by any Participant will totally lapse and expire and will not become part of a pool of Units to be allocated to other Participants. If a Participant terminates employment due to death, Disability or Normal Retirement, all Units allocated to such Participant's Account shall become fully vested. If a Participant is terminated for any reason within one year after the effective date of a Change in Control, all Units allocated to such Participant's Account shall become fully vested. SECTION 6 EXERCISE AND DISTRIBUTIONS Each Participant who has a vested Account balance under the Plan shall be entitled to exercise its Units to receive a cash payment as follows: After a Unit has vested, during the Unit's term, the Participant may exercise any number of the Participant's vested Units by filing the prescribed form with the Committee. As soon as administratively feasible following such exercise, the Participant shall be paid in cash, a lump sum amount equal to the excess of the average closing market price of GEL units as traded on the American Stock Exchange for the ten (10) trading days preceding the date of exercise over the strike price of the exercised Unit. The cash payment to each Participant upon exercise of a Unit shall be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Company to make cash payments to Participants who have exercised Units under the Plan as soon as feasible following such exercise, the Committee may authorize deferring such payments until such time as it determines, in its full discretion, that it would not cause significant financial harm to the Company to make such deferred cash payments. All deferred cash payments shall be made to the Participants in the order in which such Units were exercised. If upon the expiration of a Unit's term, the Participant has not terminated employment from and remains an employee of the Company, the Unit shall be deemed exercised as of the date of the Unit's expiration and cash payment shall be made as provided in this Section 6. In the event of a Participant's termination of employment for any reason other than death, Disability or Normal Retirement, prior to exercise of all the Participant's vested Units, any remaining vested but unexercised Units must be exercised within 3 months following the Participant's termination of employment, after which time such Units shall lapse and expire and no longer be available for either future allocation under the Plan or exercise by any Participant. In the event of a Participant's termination of employment due to death, Disability or Normal Retirement prior to the exercise of all of the Participant's vested units, any remaining 3 vested but unexercised Units must be exercised within 12 months following the Participant's termination of employment. If such Participant's ha not exercised such Units within 12 months following the Participant's termination of employment, such Units shall be deemed exercised as of the date 12 months following the Participant's termination of employment and cash payments shall be made as provided in this Section 6. In the event of a Participant's death prior to exercise of all the Participant's vested Units, any further exercise shall be made by the Participant's designated beneficiary on file with the Committee. If no such designation is on file or the beneficiary (or beneficiaries) designated therein does not survive the Participant, the exercise shall be made by the Participant's surviving spouse, or if none, by the trustee of the Participant's estate. A Participant may submit to the Committee on the form prescribed therefor, the beneficiary or beneficiaries designated by the Participant to exercise the vested Units. A Participant may update and supersede a prior beneficiary designation with a later one, which shall be controlling under the Plan if received by the Committee prior to the Participant's death. Divorce shall automatically revoke a beneficiary designation of the divorced spouse. SECTION 7 NO RIGHTS AS L.P. UNIT HOLDERS The Units under this Plan shall not carry any rights of a common unit of GEL. The Participants under this Plan shall have no rights whatsoever as a unit holder of GEL with respect to any Units under this Plan including but not limited to any right to vote or receive distributions of any kind with respect to such Units. No amount shall be added to or credited to the account of any Participant pursuant to this Plan based on or because of any distribution made to the unit holders of GEL. SECTION 8 EMPLOYMENT Nothing in this Plan shall be deemed to grant any right of continued employment to a Participant or to limit or waive any rights of the Company to terminate such employment at any time, with or without cause. SECTION 9 NONASSIGNABILITY OF UNITS The Participant's rights to any Units, any cash payment from the Plan, or any other interest of the Participant under this Plan shall not be subject to assignment, alienation, pledge, attachment, foreclosure or any other form of transfer except in the case of death for transfers of the right to receive payment for Units by a Participant's will or under the laws of descent and distribution, or except for domestic relations orders determined by the Committee to be of a qualified nature similar to the rules under the Company's qualified 401(k) retirement savings plan. The Company shall have no obligation to make payments under this Plan to any person 4 other than the Participant (or designated beneficiary), unless directed to by a court of competent jurisdiction. SECTION 10 NO TRUST FUND Participants under the Plan shall have no interest in any fund or specific asset of the Company, GEL or any other affiliate or subsidiary of the Company or GEL. No trust fund shall be created in connection with the Plan or any Units, and there shall be no advanced funding of any amounts that may become payable under the Plan. SECTION 11 ADJUSTMENTS IN THE EVENT OF CHANGES IN THE CAPITAL STRUCTURE OR REORGANIZATION--ANTI-DILUTION Changes in Capital Structure. - The Board shall make appropriate equitable adjustments to protect the Participants or the Company from any adverse financial impact which might result as a consequence of common unit splits or other changes in GEL's capital structure. SECTION 12 AMENDMENT AND TERMINATION The Board shall have the sole right at any time to terminate or amend the Plan or any part thereof except that any termination or amendment of the Plan shall not materially reduce the benefits that have previously accrued to Participants, or have the effect of reducing a Participant's benefit with respect to any vested Units then allocated to such Participant's Account. Upon a Plan termination, each Participant who has not yet terminated employment shall become fully vested in the Units in his Account and shall be entitled to a cash lump sum of the exercise value of such Units (as determined in conformity with Section 6 above) as soon as administratively feasible following the Plan termination. SECTION 13 MISCELLANEOUS (a) Expenses of the Plan. - Any expenses incurred in connection with the administration of the Plan shall be paid by the Company. (b) Tax Withholding. - The Company shall deduct from any payments to a Participant or beneficiary under the Plan any taxes required by law to be withheld with respect to such payments. (c) Applicable Law. - The terms and provisions of the Plan shall be construed in accordance with the law of the State of Texas, except to the extent preempted by federal law. (d) ERISA. - This Plan is not intended to be a pension plan under ERISA. 5 SECTION 14 DEFINITIONS (a) "Account" means the account maintained for each Participant in the Plan reflecting the number of Units allocated to such Participant in accordance with Section 4 above, vested status of such Units, and any other information necessary to properly administer the rights of the Participants. (b) "Company" for purposes of this Plan shall, unless the Committee determines otherwise, include its affiliates and GEL. (c) "Change in Control" shall be deemed to have occurred on the earliest of the following dates: (i) The date any entity or person (including a "group" within the meaning of Section 13(d)(3) of the Securities Act of 1934, or any comparable successor provisions), other than the owners of the Company at the time this Plan is adopted, shall have become the beneficial owners of, or shall have obtained voting control over, fifty percent (50%) or more of the then outstanding shares of the Company; or (ii) The closing date of any transaction to sell or otherwise dispose of substantially all of the assets of GEL or to merge or consolidate GEL with or into another partnership or corporation, in which GEL is not the continuing or surviving partnership or corporation, or pursuant to which any common units of GEL would be converted into cash, securities or other property of another partnership or corporation. (d) "Disability" means that the Participant satisfies the requirements for benefits under the Company's long-term disability plan. (e) "Normal Retirement" means that the sum of Participant's age and years of service with the Company equals or exceeds 75 years at the time the Participant terminates employment. (f) "Plan Year" means a calendar year. (g) "Units" means the stock appreciation rights or phantom units granted and allocated to the Participants under this Plan. SECTION 15 EFFECTIVE DATE Effective Date. - The effective date of the Plan is December 31, 2003. 6 EX-21.1 6 h14014exv21w1.txt SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21.1 GENESIS ENERGY, L.P. Subsidiaries of the Registrant Genesis Crude Oil, L.P. - Delaware limited partnership (99.99% limited partner interest owned by Genesis Energy, L.P.) Genesis Pipeline Texas, L.P. - Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.) Genesis Pipeline USA, L.P. - Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.) EX-31.1 7 h14014exv31w1.txt CERT. BY CEO PURSUANT TO RULE 13A-14 EXHIBIT 31.1 CERTIFICATION I, Mark J. Gorman, certify that: 1. I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting,, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 29, 2004 /s/ Mark J. Gorman ----------------------------------- Mark J. Gorman President & Chief Executive Officer EX-31.2 8 h14014exv31w2.txt CERT. BY CFO PURSUANT TO RULE 13A-14A EXHIBIT 31.2 CERTIFICATION I, Ross A. Benavides, certify that: 1. I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.; 1. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 2. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 3. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 4. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting,, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 29, 2004 /s/ Ross A. Benavides ------------------------------ Ross A. Benavides Chief Financial Officer EX-32.1 9 h14014exv32w1.txt CERT. BY CEO PURSUANT TO SECTION 906 EXHIBIT 32.1 CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Genesis Energy, L.P. (the "Partnership") on Form 10-K for the year ended December 31, 2003 (the "Report") filed with the Securities and Exchange Commission on March 29, 2004, I, Mark J. Gorman, President and Chief Executive Officer of Genesis Energy, Inc., the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Partnership's Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and (2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership. March 29, 2004 /s/ Mark J. Gorman -------------------------------------- Mark J. Gorman President and Chief Executive Officer, Genesis Energy, Inc. EX-32.2 10 h14014exv32w2.txt CERT. BY CFO PURSUANT TO SECTION 906 EXHIBIT 32.2 CERTIFICATION BY CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Genesis Energy, L.P. (the "Partnership") on Form 10-K for the year ended December 31, 2003 (the "Report") filed with the Securities and Exchange Commission on March 29, 2004, I, Ross A. Benavides, Chief Financial Officer of Genesis Energy, Inc., the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Partnership's Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and (2) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership. March 29, 2004 /s/ Ross A. Benavides --------------------------------- Ross A. Benavides Chief Financial Officer, Genesis Energy, Inc. -----END PRIVACY-ENHANCED MESSAGE-----