================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------------------------------- FORM 10-Q [X] QUARTERLY REPORT UNDER SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 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 Identification No.) incorporation or organization) 500 Dallas, Suite 2500, Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (713) 860-2500 (Registrant's telephone number, including area code) 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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes No |X| ================================================================================ This report contains 30 pages 1 GENESIS ENERGY, L.P. Form 10-Q INDEX PART I. FINANCIAL INFORMATION Item 1. Financial Statements Page ---- Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............................................. 3 Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2003 and 2002................. 4 Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2003 and 2002........... 5 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2003 and 2002................................. 6 Consolidated Statement of Partners' Capital for the Nine Months Ended September 30, 2003................................... 7 Notes to Consolidated Financial Statements........................... 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..................... 16 Item 3. Quantitative and Qualitative Disclosures about Market Risk.. 29 Item 4. Controls and Procedures..................................... 30 PART II. OTHER INFORMATION Item 1. Legal Proceedings........................................... 30 Item 6. Exhibits and Reports on Form 8-K............................ 30 SIGNATURES........................................................... 30 2 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands) (Unaudited) September 30, December 31, 2003 2002 -------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents...................................... $ 3,933 $ 1,071 Accounts receivable-trade...................................... 74,582 80,664 Inventories.................................................... 575 4,952 Other.......................................................... 5,344 5,410 ---------- ---------- Total current assets........................................ 84,434 92,097 FIXED ASSETS, at cost............................................. 119,778 118,418 Less: Accumulated depreciation................................ (74,831) (73,958) ---------- ---------- Net fixed assets............................................ 44,947 44,460 OTHER ASSETS, net of amortization................................. 1,064 980 ---------- ---------- TOTAL ASSETS...................................................... $ 130,445 $ 137,537 ========== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable - Trade....................................................... $ 75,135 $ 82,640 Related party............................................... 4,251 4,746 Accrued liabilities............................................ 8,527 8,834 ---------- ---------- Total current liabilities................................... 87,913 96,220 LONG-TERM DEBT.................................................... 6,000 5,500 COMMITMENTS AND CONTINGENCIES (Note 11) MINORITY INTERESTS................................................ 515 515 PARTNERS' CAPITAL Common unitholders, 8,625 units issued and outstanding......... 35,289 34,626 General partner................................................ 728 715 Accumulated other comprehensive income......................... - (39) ---------- ---------- Total partners' capital..................................... 36,017 35,302 ---------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 130,445 $ 137,537 ========== ========== The accompanying notes are an integral part of these consolidated financial statements. 3 GENESIS ENERGY, L.P. STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2003 2002 2003 2002 ------------ ----------- ------------ ------------ REVENUES: Gathering and marketing revenues Unrelated parties.............................. $ 233,670 $ 209,916 $ 704,166 $ 677,697 Related parties................................ - - - 3,036 Pipeline revenues................................. 5,361 6,434 16,696 15,625 ------------ ----------- ------------ ------------ Total revenues.............................. 239,031 216,350 720,862 696,358 COST OF SALES: Crude costs, unrelated parties.................... 214,926 193,469 640,664 644,178 Crude costs, related parties...................... 12,738 9,181 41,604 13,566 Field operating costs............................. 4,404 4,021 12,571 12,025 Pipeline operating costs.......................... 4,809 4,911 12,755 10,161 ------------ ----------- ------------ ------------ Total cost of sales............................ 236,877 211,582 707,594 679,930 ------------ ----------- ------------ ------------ GROSS MARGIN......................................... 2,154 4,768 13,268 16,428 EXPENSES: General and administrative........................ 1,994 2,060 6,802 6,352 Depreciation and amortization..................... 1,360 1,412 4,244 4,310 Other ............................................ (143) - (190) - ------------- ----------- ------------- ------------ OPERATING INCOME (LOSS).............................. (1,057) 1,296 2,412 5,766 OTHER INCOME (EXPENSE): Interest income................................... 6 30 21 45 Interest expense.................................. (162) (209) (877) (892) Change in fair value of derivatives............... - (1,037) - (2,094) Gain on asset disposals........................... - 23 - 698 ------------ ----------- ------------ ------------ Income (loss) before minority interest............... (1,213) 103 1,556 3,523 Minority interest.................................... - - - - ------------ ----------- ------------ ------------ NET INCOME (LOSS).................................... $ (1,213) $ 103 $ 1,556 $ 3,523 ============ =========== ============ ============ NET INCOME (LOSS) PER COMMON UNIT- BASIC AND DILUTED................................... $ (0.14) $ 0.01 $ 0.18 $ 0.40 ============ =========== ============ ============ WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING............................ 8,625 8,625 8,625 8,625 ============ =========== ============ ============ The accompanying notes are an integral part of these consolidated financial statements. 4 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands) (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2003 2002 2003 2002 ------------ ----------- ------------ ------------ NET INCOME (LOSS).................................... $ (1,213) $ 103 $ 1,556 $ 3,523 OTHER COMPREHENSIVE INCOME: Change in fair value of derivatives used for hedging purposes.......................... - - 39 - ------------ ----------- ------------ ------------ COMPREHENSIVE INCOME (LOSS).......................... $ (1,213) $ 103 $ 1,595 $ 3,523 ============ =========== =========== ============ The accompanying notes are an integral part of these consolidated financial statements. 5 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited) Nine Months Ended September 30, 2003 2002 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 1,556 $ 3,523 Adjustments to reconcile net income to net cash provided by operating activities Depreciation............................................ 4,038 3,674 Amortization of covenant not-to-compete...................................... 206 636 Amortization and write-off of credit facility issuance costs................. 903 551 Change in fair value of derivatives.......................................... 39 2,094 Minority interest's equity in earnings....................................... - - Gain on sales of fixed assets................................................ (190) (698) Other noncash charges........................................................ - 1,500 Changes in components of working capital - Accounts receivable....................................................... 6,082 89,683 Inventories............................................................... 4,129 1,967 Other current assets...................................................... 66 5,631 Accounts payable.......................................................... (8,187) (89,119) Accrued liabilities....................................................... (307) (5,832) --------- --------- Net cash provided by operating activities......................................... 8,335 13,610 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment............................................. (4,136) (2,753) Change in other assets.......................................................... (100) 1 Proceeds from sales of assets................................................... 236 2,204 --------- --------- Net cash used in investing activities............................................. (4,000) (548) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings (repayments) of debt................................................. 500 (13,900) Credit facility issuance costs.................................................. (1,093) - Distributions to common unitholders............................................. (862) - Distributions to general partner................................................ (18) - --------- --------- Net cash used in financing activities............................................. (1,473) (13,900) --------- --------- Net increase in cash and cash equivalents......................................... 2,862 (838) Cash and cash equivalents at beginning of period.................................. 1,071 5,777 --------- --------- Cash and cash equivalents at end of period........................................ $ 3,933 $ 4,939 ========= ========= The accompanying notes are an integral part of these consolidated financial statements. 6 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (In thousands) (Unaudited) Partners' Capital ------------------------------------------------------- Accumulated Other Common General Comprehensive Unitholders Partner Income Total ------------ -------- -------------- ------------ Partners' capital at December 31, 2002................. $ 34,626 $ 715 $ (39) $ 35,302 Net income for the nine months ended September 30, 2003 .............................................. 1,525 31 - 1,556 Cash distributions to partners during the nine months ended September 30, 2003............................. (862) (18) - (880) Change in fair value of derivatives used for hedging purposes............................................. - - 39 39 ---------- --------- ------------ ------------ Partners' capital at September 30, 2003................ $ 35,289 $ 728 $ - $ 36,017 The accompanying notes are an integral part of these consolidated financial statements. 7 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Formation and Offering Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in December 1996 as an initial public offering of 8.6 million Common Units, representing limited partner interests in GELP. 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"). 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. The general partner of these subsidiary partnerships is Genesis Energy, Inc. The General Partner has no income or ownership interest in the subsidiary partnerships. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to as "GCOLP". 2. Basis of Presentation The accompanying consolidated financial statements and related notes present the financial position as of September 30, 2003 and December 31, 2002 for GELP, the results of operations for the three and nine months ended September 30, 2003 and 2002, cash flows for the nine months ended September 30, 2003 and 2002, and changes in partners' capital for the nine months ended September 30, 2003. The financial statements included herein have been prepared by the Partnership without audit pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, the Partnership believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the financial statements and notes thereto included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2002 filed with the SEC. Basic net income per Common Unit is calculated on the weighted average number of outstanding Common Units. The weighted average number of Common Units outstanding for the three and nine months ended September 30, 2003 and 2002 was 8,625,000. For this purpose, the 2% General Partner interest is excluded from net income. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no effect on reported net income, total assets, total liabilities and partners' equity. 3. New Accounting Pronouncements GELP adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See Note 7. On January 1, 2003, GELP 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 had no material impact on the Partnership's financial statements. During the third quarter of 2003, the Partnership recorded termination benefits related to the sale of its Texas Gulf Coast operations in the amount of $0.3 million. See Note 12 for information regarding this sale. GELP 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 <page>8 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 11. GELP 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 either the financial position, results of operations, cash flows or disclosure requirements of the Partnership. 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. The Partnership adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on the Partnership's 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). The Partnership adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on the Partnership's financial position, results of operations or cash flows. 4. Business Segment and Customer Information The Partnership manages all of its material operations around the gathering and marketing of crude oil, and reports its operations, both internally and externally, as a single business segment. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil Company accounted for 24%, 14% and 11%, respectively, of revenues in the first nine months of 2003. ExxonMobil Corporation and Marathon Ashland Petroleum LLC accounted for 14% and 17%, respectively, of revenues in the first nine months of 2002. 5. Inventory Reduction As a result of a change in the Partnership's operations in 2001 to focus on its gathering activities, and due to changes made in its gathering business as a result of changes in its credit facilities, the Partnership determined that the volume of crude oil needed to ensure efficient and uninterrupted operation of its gathering business should be reduced. These crude oil volumes had been carried at their weighted average cost and classified as fixed assets. In the first nine months of 2002, the Partnership realized additional gross margin of approximately $889,000 as a result of the sale of these volumes. 6. Credit Resources and Liquidity In March 2003, the Partnership entered into a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Agreement"). This agreement replaced an agreement with Citicorp North America, Inc. ("Citicorp Agreement"). The Fleet Agreement has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. The key terms of the Fleet Agreement are as follows: o Letter of credit fees are based on the usage of the Fleet facility in relation to the borrowing base and will range from 2.00% to 3.00%. During the first six months of the facility the rate was 2.50%. <page>9 o 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 the Partnership's option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. During the first six months of the facility the Partnership borrowed at the prime rate plus 1.50%. o The Partnership pays 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 and will range from 0.375% to 0.50%. During the first six months of the facility, the commitment fee was 0.50%. o The amount that the Partnership may have outstanding in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Agreement generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. o Collateral under the Fleet Agreement consists of the Partnership's accounts receivable, inventory, cash accounts, margin accounts and fixed assets. o The Fleet Agreement contains covenants requiring a minimum current ratio, a maximum 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. The Partnership was in compliance with these covenants at September 30, 2003. Under the Fleet Agreement, 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 September 30, 2003, the Partnership had $6.0 million outstanding under the Fleet Agreement. Due to the revolving nature of loans under the Fleet Agreement, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At September 30, 2003, the Partnership had letters of credit outstanding under the Fleet Agreement totaling $19.3 million, comprised of $11.4 million and $7.1 million for crude oil purchases related to September 2003 and October 2003, respectively and $0.8 million related to other business obligations. Credit Availability Any significant decrease in the Partnership's financial strength, regardless of the reason for such decrease, may increase the number of transactions requiring letters of credit, which could restrict its gathering and marketing activities due to the limitations of the Fleet Agreement and Borrowing Base. This situation could in turn adversely affect its ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect its profitability and liquidity. 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, GCOLP will distribute 100% of its Available Cash, as defined, within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of the cash receipts less cash disbursements of GCOLP, adjusted for net changes to reserves. Currently, the target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. Under the Fleet Agreement, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage (working capital borrowings plus outstanding letters of credit) under the Fleet Agreement by at least $10 million plus the distribution, measured once each month. <page>10 During 2002, the Partnership did not pay any regular distributions although it met the Borrowing Base test in the last two quarters of that year. During the first three quarters of 2003, the Partnership met the test in the Fleet Agreement. A distribution of $0.05 per unit ($0.4 million in total each quarter) was paid in each of May 2003 and August 2003, covering the first and second quarters of 2003. A distribution of $0.05 per unit ($0.4 million in aggregate) payable on November 14, 2003 to Unitholders of record on October 31, 2003 has been declared for the third quarter of 2003. 7. Asset Retirement Obligations GELP adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which the obligation is incurred and can be reasonably estimated. 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. With respect to its pipelines, federal regulations will require GELP to purge the crude oil from its pipelines when the pipelines are retired. The Partnership's right of way agreements generally do not require it to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of its truck unload stations are on leased sites that require that the Partnership remove improvements upon expiration of the lease term. For its pipelines, management of the Partnership is unable to reasonably estimate and record liabilities for its obligations that fall under the provisions of this statement because it 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 management of the Partnership cannot reasonably estimate when such notice would be given and when the obligations to remove its improvements would be settled. The Partnership will record asset retirement obligations in the period in which it determines the settlement dates. In the third quarter of 2003, the Partnership 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. 8. Transactions with Related Parties Sales, purchases and other transactions with affiliated companies, except for below-market guarantee fees paid in 2002 to Salomon Smith Barney Holdings Inc. ("Salomon"), 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. Sales and Purchases of Crude Oil Denbury became a related party in May 2002. Purchases of crude oil from Denbury for the nine months ended September 30, 2003, were $41.6 million. Purchases from Denbury during the nine months ended September 30, 2002 while it was a related party (May to September) were $13.6 million and purchases during the period before it became an affiliate were $10.9 million. Purchases from Denbury are secured by letters of credit. Salomon ceased to be a related party in May 2002. During the period in 2002 when Salomon was a related party, sales totaling $3.0 million were made to Phibro Inc., a subsidiary of Salomon. General and Administrative Services The Partnership does not directly employ any persons to manage or operate its business. These services are provided by the General Partner. The Partnership reimburses the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by the Partnership were $11,929,000 and $12,854,000 for the nine months ended September 30, 2003 and 2002, respectively. <page>11 Directors' Fees The Partnership paid $90,000 to Denbury in the nine months ended September 30, 2003, for the services of four of Denbury's officers as directors of the General Partner, the same rate at which the Partnership's independent directors were paid. Credit Agreement In December 2001, Citicorp began providing the Partnership 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, the Partnership incurred letter of credit fees, interest and commitment fees totaling $396,000 under the Credit Agreement. In December 2001, the Partnership 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. Guaranty Fees From January 2002 to April 2002, Salomon provided guaranties under a transition arrangement with Salomon, Citicorp and the Partnership. For the nine months ended September 30, 2002, the Partnership paid Salomon $61,000 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. 9. Supplemental Cash Flow Information Cash received by the Partnership for interest was $21,000 and $46,000 for the nine months ended September 30, 2003 and 2002, respectively. Payments of interest were $238,000 and $453,000 for the nine months ended September 30, 2003 and 2002, respectively. 10. Derivatives The Partnership's market risk in the purchase and sale of its crude oil contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge its exposure to such market fluctuations, the Partnership may enter into various financial contracts, including futures, options and swaps. Normally, any contracts used to hedge market risk are less than one year in duration. During 2003, the Partnership has not used hedging instruments. The Partnership utilizes crude oil futures contracts and other financial derivatives to reduce its exposure to unfavorable changes in crude oil prices. Every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Partnership marks to fair value its derivative instruments at each period end with changes in fair value of derivatives not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. Unrealized gains or losses on derivative transactions qualifying as hedges are reflected in other comprehensive income. The Partnership regularly reviews its contracts to determine if the contracts qualify for treatment as derivatives. At September 30, 2003, the Partnership had no contracts outstanding that qualified for derivative treatment under SFAS No. 133. <page>12 At December 31, 2002, the Partnership determined that the only contract qualifying as a derivative was a qualifying cash flow hedge. The decrease of $39,000 in the fair value of this hedge was 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. The Partnership determined that its derivative contracts qualified for the normal purchase and sale exemption at September 30, 2003. The decrease in fair value of the Partnership's net asset for derivatives not qualifying as hedges in the first nine months of 2002 was $2.1 million. This decrease in fair value of $2.1 million is recorded as a loss in the consolidated statements of operations under the caption "Change in fair value of derivatives". 11. Contingencies Guarantees The Partnership has guaranteed $5.2 million of residual value related to the leases of tractors and trailers. Management of the Partnership believes the likelihood the Partnership would be required to perform or otherwise incur any significant losses associated with this guaranty is remote. GELP has guaranteed crude oil purchases of GCOLP. These guarantees, totaling $11.2 million at September 30, 2003, 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 Agreement related to borrowings and letters of credit. Borrowings at September 30, 2003, were $6.0 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. Unitholder Litigation On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner interests in the partnership, filed a putative class action complaint in the Delaware Court of Chancery, No. 18096-NC, seeking to enjoin a restructuring that was approved by the unitholders and completed in December 2000. On July 28, 2003, the claim was dismissed with prejudice. The plaintiff did not appeal this dismissal, therefore this matter has now been resolved. Pennzoil Litigation The Partnership was named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") seeks property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claims the fire and explosion was caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. Management of the Partnership believes that the suit is without merit and intends to vigorously defend itself in this matter. Management of the Partnership believes that any potential liability will be covered by insurance. 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. Management of the Partnership believes that the demand against Genesis is without merit and intends to vigorously defend itself in this matter.. Management of the Partnership believes that any potential liability will substantially be covered by insurance. Other Matters On December 20, 1999, the Partnership had a spill of crude oil from its Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek nearby. A portion <page>13 of the oil then flowed into the Leaf River. The oil spill is covered by insurance and the financial impact to the Partnership for the cost of the clean-up has not been material. 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. The Partnership is subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance. The Partnership is subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Such matters presently pending are not expected to have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. 12. Subsequent Events Sale of Texas Gulf Coast Operations On October 14, 2003, subsidiaries of GELP entered into a Pipeline Sale and Purchase Agreement ("PSA") with TEPPCO Crude Pipeline, L.P. ("TEPPCO"), pursuant to which TEPPCO agreed to purchase parts of GELP's Texas crude oil pipeline system and associated gathering and marketing operations (the "Texas Gulf Coast Operations"). The parts of the Texas crude oil pipeline system sold by GELP include the segments of pipeline from Hearne to Bryan, Texas, Conroe to Satsuma in northwest Houston, Texas, and Hillje and Withers to West Columbia, Texas. The gathering and marketing operations in a 40-county area surrounding these pipeline segments were also sold, and TEPPCO assumed the responsibilities under GELP's crude oil purchase and sale contracts in that area. The transaction was completed on October 31, 2003 (the "Closing Date"). TEPPCO paid GELP $21.6 million for the Texas Gulf Coast Operations. Additionally TEPPCO will purchase the crude oil inventory of GELP in the 40-county area during November 2003 at a contractually-agreed price. The Texas Gulf Coast Operations will be reflected as discontinued operations in the consolidated statement of operations beginning in the fourth quarter of 2003. TEPPCO assumed responsibility for unpaid royalties related to the crude oil purchase and sale contracts it assumed and GELP transferred $0.6 million to TEPPCO for those liabilities. On the Closing Date, GELP entered into various agreements with TEPPCO pursuant to the PSA, including (a) a transitional services agreement whereby GELP will provide to Teppco the use of certain assets TEPPCO did not acquire and pipeline monitoring services for a minimum period of six months, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with GELP the tariffs for transportation on the pipeline being sold and the segments of pipeline being retained by GELP for a one-year period. Additionally the PSA contains provisions prohibiting competition by GELP in the 40-county area for a five year period. GELP retained responsibility for environmental matters related to the Texas Gulf Coast Operations for the period prior to the Closing Date, subject to certain conditions. TEPPCO will pay the first $25,000 for each environmental claim up to an aggregate total of $100,000. GELP would be responsible for any environmental claims 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 GELP's $2 million responsibility, and GELP paid for one-half of the policy premium. GELP's responsibility to indemnify TEPPCO will cease ten years from the Closing Date. In the third quarter of 2003, the Partnership recorded $0.3 million in termination benefits related to this sale. These benefits include retention bonuses and severance pay for employees affected by the sale and are being accrued during the period that the employees are required to provide services in order to receive the benefits. Approximately $0.2 million of this amount in included in Field Operating Costs, and $0.1 million is included in Pipeline Operating Costs in the Statement of Operations. <page>14 Acquisition of CO2 Sales Contracts On October 15, 2003, the Partnership signed a letter of intent to acquire an interest in 167.5 Bcf of CO2 under a volumetric production payment, plus certain marketing rights, from Denbury Resources, Inc. ("Denbury") for $24.0 million, enabling it to commence a wholesale CO2 marketing business. As a result of this transaction, the Partnership will sell CO2 to industrial customers and pay Denbury a fee to transport the CO2 to the customers in a pipeline that Denbury owns. In a separate transaction, Genesis Energy, Inc., the General Partner of the Partnership and a wholly-owned subsidiary of Denbury, purchased 688,811 GELP Common Units for $4.9 million. These transactions are expected to close in November 2003. Distribution On October 14, 2003, the Board of Directors of the General Partner declared a cash distribution of $0.05 per Unit for the quarter ended September 30, 2003. The distribution will be paid November 14, 2003, to the General Partner and all Common Unitholders of record as of the close of business on October 31, 2003. 15 GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -1- Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Genesis Energy, L.P., operates crude oil common carrier pipelines and is an independent gatherer and marketer of crude oil in North America, with operations concentrated in Texas, Louisiana, Alabama, Florida and Mississippi. The following review of the results of operations and financial condition should be read in conjunction with the Consolidated Financial Statements and Notes thereto and with the Partnership's annual report on Form 10-K for the year ended December 31, 2002. Included in Management's Discussion and Analysis are the following sections: o 2003 Highlights o Results of Operations o Outlook for the Remainder of 2003 and Beyond o Liquidity and Capital Resources o Forward Looking Statements 2003 Highlights In May 2003, we resumed distributions to partners in the Partnership by making a distribution for the first quarter of 2003 in the amount of $0.05 per unit for a total of $0.4 million. A distribution of $0.05 per unit was also paid in August 2003 for the second quarter of 2003 and we have declared a distribution for the third quarter of 2003, payable November 14, 2003 to unitholders of record on October 31, 2003, and the general partner in the amount of $0.05 per unit. During the first nine months of 2003, we replaced the credit facility with Citicorp North America, Inc. ("Citicorp") with a three-year $65 million credit facility with a group of banks, with Fleet National Bank as agent ("Fleet Agreement"). The Fleet Agreement replaced an $80 million credit facility that was to expire in December 2003. Reduction of the size of the credit facility to a size in line with our needs reduces the commitment fees we are required to pay. Obtaining a facility for a three-year period provides a source of funding and credit for a longer term and provides additional financial institutions that may make access to debt capital easier as we grow. The Fleet Agreement has terms that are summarized more fully below and in Note 6 to the Consolidated Financial Statements. As a result of the replacement of the Citicorp Agreement, the unamortized portion of the fees paid in December 2001 to obtain the Citicorp Agreement were charged to expense in the first quarter of 2003. The total of fees charged to expense was $0.6 million, with $0.2 million included in general and administrative expenses and the remainder classified as interest expense. On October 31, 2003, we sold parts of our Texas crude oil pipeline system and associated gathering and marketing operations (the "Texas Gulf Coast Operations") to TEPPCO Crude Pipeline, L.P. ("TEPPCO"). The parts of the Texas crude oil pipeline system sold include the segments of pipeline from Hearne to Bryan, Texas, Conroe to Satsuma in northwest Houston, Texas, and Hillje and Withers to West Columbia, Texas. The gathering and marketing operations in a 40-county area surrounding these pipeline segments were also sold, and TEPPCO assumed the responsibilities under our crude oil purchase and sale contracts in that area. TEPPCO paid us $21.6 million for the Texas Gulf Coast Operations. See Note 12 of Notes to Consolidated Financial Statements for additional information on this sale. Additionally see the Form 8-K filed dated October 31, 2003 for the pro forma effects of this sale. On October 15, 2003, we signed a letter of intent to acquire an interest in 167.5 Bcf of CO2 under a volumetric production payment, plus certain marketing rights, from Denbury Resources, Inc. ("Denbury") for $24.0 million, enabling us to commence a wholesale CO2 marketing business. As a result of this transaction, we will sell CO2 to industrial customers and pay Denbury a fee to transport the CO2 to the customers in a pipeline that Denbury owns. In a separate transaction, Genesis Energy, Inc., our General Partner, purchased 688,811 GELP Common Units for $4.9 million. These transactions are expected to close in November 2003 <page>16 Results of Operations Financial and volumetric information for this discussion of the results of operations follows, in thousands, except volumes per day. Three Months Ended Nine Months Ended September 30, September 30, 2003 2002 2003 2002 ------------ ----------- ------------ ------------ Gross margin (excluding depreciation) Gathering and marketing revenues.......... $ 233,670 $ 209,916 $ 704,166 $ 680,733 Crude costs............................... 227,664 202,650 682,268 657,744 Field operating costs..................... 4,404 4,021 12,571 12,025 ------------ ----------- ------------ ------------ Gathering and marketing gross margin...... $ 1,602 $ 3,245 $ 9,327 $ 10,964 ============ =========== ============ ============ Pipeline revenues......................... $ 5,361 $ 6,434 $ 16,696 $ 15,625 Pipeline operating costs.................. 4,809 4,911 12,755 10,161 ------------ ----------- ------------ ------------ Pipeline gross margin..................... $ 552 $ 1,523 $ 3,941 $ 5,464 ============ =========== ============ ============ Barrels per day Wellhead.................................. 60,155 60,044 60,135 64,308 Bulk and exchange......................... 24,075 23,243 22,827 42,738 Pipeline.................................. 68,029 75,172 70,285 75,385 Our profitability depends to a significant extent upon our ability to maximize gross margin (excluding depreciation). Gross margins (excluding depreciation) from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels for crude oil do not necessarily bear a relationship to gross margin (excluding depreciation) as absolute price levels normally impact revenues and cost of sales by equivalent amounts. Because period-to-period variations in revenues and cost of sales are not generally meaningful in analyzing the variation in gross margin (excluding depreciation) 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 between the wellhead and the end user (usually a refinery) where we can achieve positive gross margins (excluding depreciation). We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transport the crude by truck or pipeline for sale to or exchange with customers. We generally enter into exchange transactions only when the cost of the exchange is less than the alternate cost we would incur in transporting or storing the crude oil. In addition, we often exchange one grade of crude oil for another to maximize margins or meet contract delivery requirements. 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. Pipeline revenues and gross margin (excluding depreciation) are primarily a function of the level of throughput and storage activity and are generated by the difference between the regulated published tariff and the fixed and variable costs of operating the pipeline. Changes in revenues, volumes and pipeline operating costs, therefore, are relevant to the analysis of financial results of our pipeline operations and are addressed in the following discussion of our pipeline operations. <page>17 Nine Months Ended September 30, 2003 Compared with Nine Months Ended September 30, 2002 Gathering and marketing gross margin excluding depreciation, Gross margin (excluding depreciation) from gathering and marketing operations was $9.3 million for the nine months ended September 30, 2003 and $11.0 million for the same period in 2002. The decrease in gross margin (excluding depreciation) was the result of several factors. Gross margin (excluding depreciation) decreased in 2003 due to the following factors: o a $5.1 million decrease in gross margin due to a reduction of 22 percent in wellhead, bulk and exchange purchase volumes between the 2002 and 2003 periods; o a $0.9 million increase in gross margin in the 2002 period as a result of the sale of crude oil that was no longer needed to ensure efficient and uninterrupted operations; no such sale occurred in the 2003 period; o a $0.1 million increase in field operating costs due to the costs to dispose of water in the tanks at one of our facilities; o a $0.2 million increase in field operating costs due to termination benefits recorded in the 2003 period related to employees affected by the sale of the Texas Gulf Coast Operations; o a $0.2 million increase in field operating costs due to higher diesel fuel costs to operate the Partnership's tractor/trailers, plus the costs of repairs to truck unloading stations, partially offset by lower payroll costs; and o a $0.2 million increase in credit costs due to the use of letters of credit in 2003 at a higher cost than the Salomon guaranties used from January to April 2002. These decreases in gross margin (excluding depreciation) in 2003 were partially offset by a $5.0 million increase in gross margin due to price variances - 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. The key drivers affecting our gathering and marketing gross margin (excluding depreciation) include production volumes, P-Plus margins, grade differentials, inventory management, and credit costs. A significant factor affecting our gathering and marketing gross margins (excluding depreciation) is changes in the domestic production of crude oil. Short-term and long-term price trends impact the amount of capital that producers have available to maintain existing production and to invest in developing crude reserves, which in turn impacts the amount of crude oil that is available to be gathered and marketed by us and our competitors. The volatility in prices over the last four years makes it very difficult to estimate investments that producers will make in finding and developing crude oil reserves, and therefore the volume available to purchase in future periods is difficult to estimate. We expect to continue to be subject to volatility and long-term declines in the availability of crude oil production for purchase. During the first quarter of 2003 market prices for crude oil fluctuated significantly due to world conditions. The conflict in Iraq led to expectations of disruptions in crude oil supply which caused prices to increase dramatically. The anticipation of a quick ending to the conflict and the lack of damage to the oil fields of Iraq then caused prices to decline beginning in March. The effects of strikes in Venezuela also impacted crude oil prices during the first quarter. Prices stabilized during the second and third quarters of 2003. 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, so that the changes in prices do not necessarily have a direct impact on our profitability. 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 market factor in the sales contracts is usually the price quoted by Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is <page>18 fixed and P-Plus floats in the sales contracts, the margin on an individual transaction can vary from month-to-month depending on changes in the P-Plus component. P-Plus does not necessarily move in correlation with the price of oil in the market. P-Plus is affected by numerous factors, such as future expectations for changes in crude oil prices, so that at times 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. Month Average P-Plus WTI Posting ----- -------------- ----------- December $3.9130 $26.2177 January $3.4690 $29.5161 February $4.3850 $32.3839 March $4.5470 $29.9919 April $5.1440 $25.0250 May $4.9670 $24.8790 June $3.7080 $27.2333 July $4.6870 $27.5242 August $3.9029 $28.3952 September $3.5110 $25.1000 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 have to give 30-days notice to cancel and renegotiate the contract. This notice requirement means that at least a month will pass before the fixed bonus can be increased or can be reduced to correspond with an increase or decrease in the P-Plus component of the related sales contract. If P-Plus is rising, our margin will benefit until we are asked to increase the fixed bonus. When P-Plus is declining, our margin is reduced until such a change is made. Because of the volatility of P-Plus, it is not practical to renegotiate every purchase contract for every change in P-Plus. So margins from the sale of crude oil can be volatile as a result of these timing differences. During the first half of 2003, we benefited from the 31% increase in P-Plus from December 2002 to April 2003. However, as P-Plus increased, we adjusted bonuses on some of our purchase contracts. When P-Plus declined in June, August and September, we experienced declines in margins. Until we give the required notice and renegotiate the purchase contract bonuses, or unless P-Plus increases, our margins will be reduced. We also saw fluctuations in grade differentials during the first nine months of 2003. 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 oil. We may buy oil under a contract where we considered the typical grade differences in the market in setting 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, we can experience an increase or decrease in our gross margin (excluding depreciation) 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 for December 2002 and each month of the first nine months of 2003 and the differential between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for the same periods. Grade differentials fluctuate based on the needs of refiners and the real or perceived availability of the different crude types. <page>19 WTI/WTS WTI/LLS Month Differential Differential ----- ------------ ------------ December $(2.243) $(0.008) January $(1.569) $ 0.510 February $(1.404) $ 0.692 March $(4.109) $ 0.178 April $(4.797) $(0.065) May $(3.270) $(0.257) June $(1.499) $ 0.026 July $(2.379) $(0.336) August $(2.310) $(0.251) September $(2.640) $(0.116) This volatility in grade differentials can affect the volatility of our gathering and marketing gross margins (excluding depreciation). 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 typically 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 given month, they cannot predict exactly how much oil will be produced. Our sales contracts typically state a specific volume to be sold, which is determined prior to the month of production. Consequently, if the actual production gathered by us is more or less than we expected and sold, we will either increase or decrease our inventory volume. Under our risk management policy and the terms of the Fleet Facility, we are not allowed to speculate on the price of crude oil and are required to hedge our inventory if it exceeds certain levels. As a result, the main objective of inventory management is minimizing the variances in the volumes between purchases and sales and eliminating the volume variances that inevitably result. Pipeline gross margin excluding depreciation. Pipeline gross margin (excluding depreciation) was $4.0 million for the nine months ended September 30, 2003, as compared to $5.5 million for the first nine months in 2002. The $1.5 million decrease in pipeline gross margin (excluding depreciation) was due to the following factors: o a $4.1 million increase in pipeline operating costs in the 2003 period. In the third quarter of 2003, we recorded an asset retirement obligation of $0.7 million related to an offshore pipeline. Additionally we recorded $0.1 million of termination benefits related to employees affected by the sale of the Texas Gulf Coast Operations. Pipeline operating costs increased $0.2 million for personnel and benefits costs related to additions 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 $0.9 million. Expenses for maintenance of tanks, pumps and meters increased $0.1 million. Expenses for purging lines and removal of related equipment increased $0.3 million. In 2003, we increased safety training for pipeline operations personnel at a cost of $0.2 million. During the third quarter of 2002, we undertook a project to add our pipelines to the National Pipeline Mapping System with Global Positioning Satellite (GPS) information on our pipeline maps as required by pipeline safety regulations. Expenses incurred on this project in the first nine months of 2003 totaled $0.7 million. Insurance costs increased $0.3 million due to the combination of insurance market conditions and our loss history. Maintenance costs related to the pipe, including corrosion control, increased $0.1 million. Other operating costs, including power costs, increased a total of $0.4 million; o a $0.4 million decrease in revenues from sales of pipeline loss allowance barrels primarily as a result of lower volumes; and o a $0.8 million decrease in revenues due to a decline in throughput of 7% between the two periods. <page>20 Largely offsetting these decreases were the following factors: o a $2.3 million increase in revenue due to a 20 percent increase in the average tariff on shipments; and o the 2002 period increase in our accrual for fines and penalties of $1.5 million related to the oil spill in Mississippi in 1999; no such accrual occurred in the 2003 period. During the first nine months of 2003, volumes averaged 70,285 barrels per day, with 47,498 barrels per day of that volume on the Texas System, 8,226 barrels per day on the Mississippi System and 14,561 barrels per day on the Jay System. Although we sold the Texas Gulf Coast Operations, we expect volumes for the next year on our remaining pipeline segments in Texas to remain consistent with the third quarter 2003 levels. The volumes on the Mississippi System of 8,226 barrels per day were less than the fourth quarter 2002 average of 9,915 barrels per day. During the first nine months of 2003, volumes from parties other than Denbury Resources declined. We expect Mississippi System volumes for the remainder of 2003 to average between 6,500 and 7,500 barrels per day. We had anticipated that a connecting carrier would begin shipping on the Liberty-to-near-Baton Rouge segment of the Mississippi System that has been out-of-service since February 1, 2002, during the latter half of 2003. It now appears unlikely that shipments of any significance on this segment will begin before 2004, as sufficient volumes do not appear to be available for shipment. The volumes on the Jay System were 14,561 barrels per day for the first nine months of 2003. During the fourth quarter of 2002, volumes on this system averaged 14,748 barrels. We were recently advised by a producer near our pipeline that development plans for their fields in the area have been postponed until the fourth quarter of 2003, so it is unlikely that we will see any increase in volume on this system until late in 2003. The tariff increases we obtained in 2002 have continued to benefit 2003's pipeline revenues, and additional increases went into effect in July 2003 on the Jay system. Gross margin (excluding depreciation) from pipeline operations was positively impacted by the recognition of revenue from volumes related to the pipeline loss allowances and quality deductions from shipper volumes in excess of volumetric measurement losses. During the first nine months of 2003, we recognized revenue of $2.8 million related to these deductions from shippers net of losses, which totaled approximately 101,000 barrels. Additionally we realized $0.4 million of revenue from the sale of volumes in inventory at December 31, 2002 due to the rise in prices. If crude oil market prices continue their recent decline, revenues from these net deductions may be less. Expenses and Other. General and administrative expenses increased $0.5 million between the 2003 and 2002 nine month periods. This increase is primarily attributable to the write-off of $0.2 million of unamortized legal and consultant costs related to the Citicorp Agreement and an accrual of $0.2 million related to the reinstatement of the Partnership's bonus program for employees. Other general and administrative costs increased by $0.1 million. The write-off of the unamortized costs was necessitated by the replacement of the Citicorp Agreement with the Fleet Agreement. Under the Partnership's bonus program, bonuses were eliminated unless distributions were being paid, which resulted in no accrual in the 2002 period. Changes in personnel reduced salaries and benefits $0.4 million in the 2003 period; however, this decrease was completely offset by increased legal, audit and other consultant fees, directors' fees and insurance premiums for officers and directors liability insurance. We expect to incur increased costs to comply with SEC regulations mandated by the Sarbanes-Oxley Act in 2003.. Depreciation and amortization expense was flat between the nine month periods. Property additions during 2002 and 2003 increased depreciation; however, a covenant not-to-compete was fully amortized at March 31, 2003, so amortization expense in 2003 was less than in the prior year period. Interest expense was flat between the two periods. In the 2003 period, the Partnership wrote off $0.4 million of unamortized facility costs related to the Citicorp Agreement, in addition to the write-off of legal and consultant costs in general and administrative expenses noted above. However differences in the facility size during the nine-month periods offset this increase, due to higher commitment fees in the 2002 period. The facility size was $130 million from January 1, 2002, through early May 2002, when it was reduced to $80 million. In the 2003 nine-month <page>21 period, the facility was $80 million until March 14, 2003, when the Fleet Facility of $65 million replaced the Citicorp Agreement. As a result of these differences, commitment fees were $0.2 million greater in 2002. Additionally, amortization of facility fees and interest expense, in total, were $0.2 million more in 2002. As a result of a review of contracts existing at September 30, 2003, we determined that 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. We adopted SFAS No. 149, which amends SFAS No. 133 on July 1, 2003. This statement had no effect on the results for the nine-month period. In the 2002 period, the contracts were designated as normal purchases and sales, and the recorded net asset of $2.1 million was charged to expense in that period, and was included in the consolidated statements of operations in "Change in Fair Value of Derivatives". The gain on asset disposals in the 2002 period included a gain of $0.5 million from the sale of the Partnership's memberships in the New York Mercantile Exchange ("NYMEX"). Three Months Ended September 30, 2003 Compared with Three Months Ended September 30, 2002 Gathering and marketing gross margin excluding depreciation. Gross margin (excluding depreciation) from gathering and marketing operations was $1.6 million for the quarter ended September 30, 2003, as compared to $3.2 million for the quarter ended September 30, 2002. Gross margin (excluding depreciation) decreased in the third quarter of 2003 due to the following factors: o a $0.8 million decrease in the 2003 period due to price variances - 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, resulting primarily from the 25% decline in P-Plus from July to September; o a $0.6 million increase in gross margin in the 2002 period as a result of the sale of crude oil that was no longer needed to ensure efficient and uninterrupted operations; no such sale occurred in the 2003 period; o a $0.1 million increase in field operating costs due to the costs to dispose of water in the tanks at one of our facilities; and o a $0.2 million increase in field operating costs due to termination benefits recorded in the 2003 period related to employees affected by the sale of the Texas Gulf Coast Operations. These decreases in gross margin (excluding depreciation) in 2003 were partially offset by a $0.1 million increase due to a 1 percent improvement in wellhead, bulk and exchange purchase volumes between 2002 and 2003. Credit costs were flat between the two quarterly periods. Pipeline gross margin excluding depreciation. Pipeline gross margin (excluding depreciation) was $0.6 million for the quarter ended September 30, 2003, as compared to $1.5 million for the third quarter of 2002. This $0.9 million decrease in pipeline gross margin (excluding depreciation) was due to: o a $1.4 million increase in pipeline operating costs; o a $0.9 million decrease in revenues from sales of pipeline loss allowance barrels primarily as a result of lower volume; and o a $0.4 million decrease in revenue due to a decline in throughput of 10 percent between the two periods. Partially offsetting these decreases were the following factors: o a $0.3 million increase in revenue due to a 7 percent increase in the average tariff on shipments; and o the 2002 period increase in our accrual for fines and penalties of $1.5 million related to the oil spill in Mississippi in 1999; no such accrual occurred in the 2003 period. <page>22 The increased pipeline operating costs included an asset retirement obligation of $0.7 million recorded in the 2003 period related to an offshore pipeline. Additionally we recorded $0.1 million of termination benefits related to employees affected by the sale of the Texas Gulf Coast Operations. Also contributing to the increase was $0.2 million related to the GPS project and $0.6 million related to integrity testing of the pipelines, offset by a decrease of $0.2 million related to maintenance of the pipe, including corrosion control. Expenses and Other. General and administrative expenses and interest costs were flat between the two third quarter periods. As a result of the designation of our contracts as normal purchases and sales, the recorded net asset of $1.0 million was charged to expense in the 2002 period. Outlook for the Remainder of 2003 and Beyond The information below is provided as an update to the "Outlook for 2003 and Beyond" section of our Annual Report on Form 10-K for the year ended December 31, 2002. Remainder of 2003 The sale of the Texas Gulf Coast Operations closed on October 31, 2003. We expect to report a gain on this sale of approximately $12.0 million during the fourth quarter. See the Form 8-K dated October 31, 2003 for pro forma information of the effects of this sale. We expect our gathering and marketing operations to perform better in the fourth quarter than the third quarter of 2003, but not as well as the first two quarters of 2003. Margins are expected to be lower in the final quarter due to continuing market pressure on P-Plus. Pipeline gross margin excluding depreciation for the final quarter of 2003 is expected to be generally consistent with that in the first half of the year. We expect the gross margin excluding depreciation from the CO2 activities being acquired from Denbury and the termination of the Texas Gulf Coast Operations sold to Teppco to generally offset each other. 2004 During 2004, we expect to generate gross margin before depreciation from the wholesale CO2 marketing business that will offset the gross margin before depreciation from the Texas Gulf Coast operations that were sold. However, expected 2004 maintenance capital expenditures have been reduced by $6.6 million to $3.1 million as a result of the sale of the Texas Gulf Coast Operations. Distribution Expectations As a master limited partnership, the key consideration of our Unitholders is the amount of our distribution, its reliability and the prospects for distribution growth. We made no regular distributions during 2002. We paid a regular distribution of $0.05 per Unit for the first and second quarters of 2003, and we have declared a distribution for the third quarter of $0.05 per unit payable on November 14, 2003 to Common Unitholders of record on October 31, 2003, and the General Partner. As a result of the sale of the Texas Gulf Operations and the acquisition of the CO2 contracts, we expect to increase our regular quarterly distribution for the fourth quarter of 2003 to $0.15. We would expect to pay that distribution in the first quarter of 2004. Under the Fleet Agreement, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage (working capital borrowings plus outstanding letters of credit) under the Fleet Agreement by at least $10 million plus the distribution, measured once each month. During the third quarter of 2003, we exceeded the requirement by at least $25 million at each measurement date. We expect to be able to sustain a regular quarterly distribution of $0.15 per unit starting with the distribution that will be paid for the fourth quarter of 2003. We continue to expect to restore the targeted minimum quarterly distribution of $0.20 per unit in 2005. However, as we gain experience with the new asset base, as cost savings initiatives are implemented, and as opportunities to make accretive acquisitions are developed, we may be able to restore the targeted minimum quarterly distribution of $0.20 per unit during 2004. <page>23 Liquidity and Capital Resources Cash Flows During the first nine months of 2003, we generated cash flows from operating activities of $8.3 million as compared to $13.6 million for the same period in 2002. In 2003, we reduced our inventories by $4.1 million while changes in other components of working capital used cash of $2.3 million. Net income was $1.5 million and depreciation of assets and amortization of assets and deferred charges was $5.0 million. In the first nine months of 2002, net income was $3.5 million and depreciation and amortization and other non-cash items were $7.8 million. The change in components of working capital provided cash of $2.3 million. Factors related to the timing of cash receipts and payments related to the exit of the bulk and exchange business at the end of 2001 were the primary reasons for the fluctuation in our current assets and liabilities in the 2002 period. Cash flows used in investing activities in the first nine months of 2003 were $4.0 million as compared to cash flows used in investing activities of $0.5 million in the 2002 period. In 2003 we expended $4.1 million for property and equipment additions, including maintenance capital expenditures totaling $3.5 million, as further described below. Partially offsetting these expenditures in 2003 were sales of surplus assets for $0.2 million. We also incurred costs totaling $0.1 million related to the CO2 contract acquisition. In the first quarter of 2002, we sold our two seats on the NYMEX for $1.7 million. In the 2002 period, we also received $0.5 million from the disposal of additional surplus assets, while expending $2.8 million for property additions. Net cash expended for financing activities was $1.5 million in the first nine months of 2003. We expended $1.1 million for fees related to obtaining the Fleet Agreement. We paid cash distributions totaling $0.9 million to the limited partners and general partner. Partially offsetting these outflows was an increase in the outstanding balance of our long-term debt of $0.5 million. In the 2002 period, we repaid $13.9 million of debt under our credit facility. No cash distributions were paid in the 2002 period. Capital Expenditures As discussed above, we expended a total of $4.1 million in the first nine months of 2003 on capital expenditures, with $3.5 million of that amount for maintenance capital expenditures on property and equipment, and $0.6 million to acquire a condensate storage facility in Texas. Maintenance capital expenditures are expenditures that are needed to maintain the existing operating capacity of partially or fully depreciated assets or are needed to extend their useful lives. We spent $0.5 million for installation of pipeline satellite monitoring capabilities, $1.2 million for capital expenditures on the Mississippi Pipeline System, $1.2 million on the Texas Pipeline System, and $0.6 million for truck unloading additions and computer hardware and software. The $1.2 million spent for the Mississippi Pipeline System was for two purposes. First, we made 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. Second, we 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. In the first half of 2003, we continued to upgrade the West Columbia segment of our Texas pipeline. For the remainder of 2003, we estimate our capital expenditures will be less than $0.5 million, with substantially all of it to be spent on pipeline improvements such as equipment upgrades for pipeline monitoring and corrosion control. In 2004, currently we expect the level of capital expenditures to be approximately $3.1 million, with $2.5 million for pipeline integrity improvements and the $0.6 million balance for tankage and other improvements. By the end of 2004, we expect to have incurred most of the significant costs related to the IMP regulatory compliance and expect to only spend $2.1 million in 2005 for capital items, with $1.6 million related to IMP. Expenditures in years after 2006 should remain in the $0.5 million to $1.5 million level annually, as the expected integrity improvements should not be as great on the remaining segments of the pipelines. <page>24 Capital Resources Our $65 million three-year credit facility with a group of banks led by Fleet National Bank has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. At September 30, 2003, we had $6.0 million outstanding under the Fleet Agreement. The average daily balance outstanding during the quarter ended September 30, 2003 was $0.1 million. Due to the revolving nature of loans under the Fleet Agreement, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 31, 2006. At September 30, 2003, we had letters of credit outstanding under the Fleet Agreement totaling $19.3 million, comprised of $11.4 million and $7.1 million for crude oil purchases related to September 2003 and October 2003, respectively, and $0.8 million related to other business obligations. The amount of our outstanding cumulative working capital borrowings and letters of credit is subject to a borrowing base calculation. The borrowing base generally includes our cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. At September 30, 2003, the Borrowing Base was $52.2 million. Collateral under the Fleet Agreement consists of our accounts receivable, inventory, cash accounts, margin accounts and property and equipment. The Fleet Agreement contains covenants (as defined in the Fleet Agreement) requiring a current ratio, a leverage ratio, a cash flow coverage ratio, a funded indebtedness to capitalization ratio, minimum EBITDA, and limitations on distributions to Unitholders. Under the Fleet Agreement, distributions to Unitholders and the General Partner can only be made if certain tests are met. See additional discussion above under "Distributions". We were in compliance with all of these covenants at September 30, 2003. Any significant decrease in our financial strength, regardless of the reason for such decrease, may increase the number of transactions requiring letters of credit, which could restrict our gathering and marketing activities due to the limitations of the Fleet Agreement and Borrowing Base. This situation could in turn adversely affect our ability to maintain or increase the level of our purchasing and marketing activities or otherwise adversely affect our profitability and liquidity. Working Capital Our balance sheet reflects negative working capital of $3.5 million, $3.0 million of which is attributed to the accrual for the fines and penalties that we expect to pay to state and federal regulators related to our December 1999 Mississippi oil spill. Additionally, we have received funds for purchases of crude oil that have not yet been paid out to the owners of the oil, as those parties have not been located or ownership issues exist. These funds, referred to as suspended royalties, totaled $3.8 million at September 30, 2003, and have been applied to the outstanding balance owed to Fleet. As we have a working capital sublimit under the Fleet Agreement of $25 million and have only borrowed $6.0 million at September 30, 2003, we have the ability to borrow the funds to make the necessary payments. The accrual for the fines and penalties and the suspended royalties are reflected as current liabilities. Should we be required to make these payments, we will borrow the funds under the Fleet Agreement, thereby increasing the outstanding balance of long-term debt by $6.8 million and reducing current liabilities and increasing working capital by $6.8 million. 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 $74.6 million aggregate receivables on our consolidated balance sheet at September 30, 2003, approximately $74.2 million, or 99.5%, were less than 30 days past the invoice date. Contractual Obligation and Commercial Commitments In addition to the Fleet Agreement discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes these obligations and commitments at September 30, 2003 (in thousands). <page>25 Payments Due by Period ----------------------------------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations 1 Year Years Years Years Total ---------------------------- ------------ ------------ ----------- ------------ ------------ Fleet Agreement.......... $ - $ 6,000 $ - $ - $ 6,000 Operating Leases......... 4,206 4,926 1,793 1,849 12,774 Unconditional Purchase Obligations (1) 99,534 - - - 99,534 ------------ ------------ ----------- ------------ ------------ Total Contractual Cash Obligations $ 103,740 $ 10,926 $ 1,793 $ 1,849 $ 118,308 ============ ============ =========== ============ ============ <FN> (1) The unconditional purchase obligations included above are contracts to purchase crude oil, generally at market-based prices. For purposes of this table, market prices at September 30, 2003, were used to value the obligations, such that actual amounts paid may differ from the amounts included above. </FN> As a result of the assignment to Teppco of operating leases related to tractors and trailers used in the Texas Gulf Coast Operations, our total operating leases will decrease by $4.2 million in total. Distributions The Partnership Agreement for Genesis Energy, L.P. provides that we will distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to reserves. The Partnership Agreement indicates that the target minimum quarterly distribution for each quarter is $0.20 per unit. Available Cash before reserves for the quarter and nine months ended September 30, 2003, is as follows (in thousands): Three Nine Months Months Ended Ended September 30, September 30, 2003 2003 --------- --------- AVAILABLE CASH BEFORE RESERVES: Net income (loss).................................................... $ (1,213) $ 1,556 Depreciation and amortization........................................ 1,360 4,244 Cash proceeds in excess of gains on asset sales...................... 6 46 Maintenance capital expenditures..................................... (539) (3,479) --------- --------- Available Cash before reserves....................................... $ (386) $ 2,367 ========= ========= Available Cash is a non-GAAP measure. For further information on available cash and a reconciliation of this measure to cash flows from operating activities, see "Non-GAAP Financial Measure" below. We declared a distribution for the third quarter in the amount of $0.05 per unit ($0.4 million in total) payable on November 14, 2003, to Common Unitholders of record at the close of business on October 31, 2003, and to the General Partner. While we did not earn sufficient Available Cash in the third quarter for this distribution, we had reserves from the first half of the year from which to pay the distribution. We expect to make a regular quarterly distribution for the fourth quarter of 2003 of $0.15 per unit, which will be paid in February 2004. Thereafter, any decision to restore the distribution to the targeted minimum quarterly distribution will take into account our ability to sustain the distribution on an ongoing basis with cash generated by our existing asset base, capital requirements needed to maintain and optimize the performance of our asset base, and our ability to finance our existing capital requirements and accretive acquisitions. <page>26 Non-GAAP Financial Measure The non-GAAP financial measure of Available Cash is presented in this Form 10-Q. The amounts used in calculating this measure are computed 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 defined as capital expenditures (as defined by GAAP) which do not increase the capacity of an asset or generate additional revenues or cash flow from operations. 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 for the quarter and nine months ended September 30, 2003, is as follows (in thousands): Three Nine Months Months Ended Ended September 30, September 30, 2003 2003 --------- --------- Cash flows from operating activities................................. $ 2,086 $ 8,335 Adjustments to reconcile operating cash flows to Available Cash: Maintenance capital expenditures................................. (539) (3,479) Proceeds from asset sales........................................ 149 236 Change in fair value of derivatives.............................. - (39) Amortization of credit facility issuance fees.................... (62) (903) Net effect of changes in operating accounts not included in calculation of Available Cash................................. (2,020) (1,783) --------- --------- Available Cash before reserves....................................... $ (386) $ 2,367 ========== ========= 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. <page>27 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. Critical Accounting Policies and Recent Accounting Pronouncements For a discussion of our critical accounting policies, which are related to depreciation, amortization and impairment, revenue and expense accruals and liability and contingency accruals, and which remain unchanged, see our annual report on Form 10-K for the year ended December 31, 2002. We continuously monitor and revise our accounting policies as relevant accounting literature changes. At this time there are several new accounting pronouncements that have been recently issued which will or may impact our accounting or disclosure, as they become effective. For further discussion of new accounting rules, see Item 1. Consolidated Financial Statements-Note 3 Recent Accounting Pronouncements. Forward Looking Statements The statements in this report on Form 10-Q that are not historical information may be forward looking statements within the meaning of Section 27a of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although we believe that its expectations regarding future events are based on reasonable assumptions, no assurance can be made that our goals will be achieved or that expectations regarding future developments will prove to be correct. Important factors that could cause actual results to differ materially from the expectations reflected in the forward looking statements herein include, but are not limited to, the following: o changes in regulations; o our success in obtaining additional wellhead barrels; o changes in crude oil production volumes (both world-wide and in areas in which we have operations); o developments relating to possible acquisitions, dispositions or business combination opportunities; o volatility of crude oil prices, P-Plus prices and grade differentials; o the success of risk management activities; o credit requirements by our counterparties; o the ability to obtain liability and property insurance at a reasonable cost; o acts of sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; o our ability in the future to generate sufficient amounts of Available Cash to permit the payment to unitholders of a quarterly distribution; o any additional requirements for testing or changes in the Mississippi pipeline system as a result of the oil spill that occurred there in December 1999; o any fines and penalties federal and state regulatory agencies may impose in connection with the oil spill that would not be reimbursed by insurance; o the costs of testing under pipeline integrity management programs and any rehabilitation required as a result of that testing; o estimated timing and amount of future capital expenditures; o our success in increasing tariff rates on our common carrier pipelines; o results of current or threatened litigation; and o conditions of capital markets and equity markets during the periods covered by the forward looking statements. <page>28 All subsequent written or oral forward looking statements attributable to us, or persons acting our behalf, are expressly qualified in their entirety by the foregoing cautionary statements. Item 3. Quantitative and Qualitative Disclosures about Market Risk Price Risk Management and Financial Instruments The Partnership's primary price risk relates to the effect of crude oil price fluctuations on its inventories and the fluctuations each month in grade and location differentials and their effects on future contractual commitments. Historically, the Partnership has utilized New York Mercantile Exchange ("NYMEX") commodity based futures contracts, forward contracts, swap agreements and option contracts to hedge its exposure to market price fluctuations; however, at September 30, 2003, no contracts were outstanding. Information about inventory at September 30, 2003, is contained in the table set forth below. Crude Oil Inventory Volume in barrels................................ 180,000 Carrying value .................................. $ 3,872,000 Fair value....................................... $ 5,070,000 Fair values were determined by using the notional amount in barrels multiplied by published market closing prices for the applicable crude oil type at September 30, 2003. As a result of a review of contracts existing at September 30, 2003, we determined that 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. We adopted SFAS No. 149, which amends SFAS No. 133 on July 1, 2003. This statement had no effect on the results for the nine-month period. 29 Item 4. Controls and Procedures The Partnership has evaluated the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Such evaluation was conducted under the supervision and with the participation of the Partnership's Chief Executive Officer ("CEO") and its Chief Financial Officer ("CFO"). Based upon such evaluation, the Partnership's CEO and CFO have concluded that the Partnership's disclosure controls and procedures are effective in ensuring that information required to be disclosed is recorded, processed, summarized and reported in a timely manner. There has been no change in the Partnership's internal control over financial reporting that occurred during the last fiscal quarter that has materially affected, or is reasonably likely to affect, the Partnership's internal control over financial reporting. PART II. OTHER INFORMATION Item 1. Legal Proceedings See Part I. Item 1. Note 10 to the Consolidated Financial Statements entitled "Contingencies", which is incorporated herein by reference. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 Exhibit 32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Exhibit 32.2 Certification by Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (b) Reports on Form 8-K. A report on Form 8-K was filed on August 11, 2003 containing the Partnership's earnings press release for the second quarter of 2003. SIGNATURES Pursuant to the requirements 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. GENESIS ENERGY, L.P. (A Delaware Limited Partnership) By: GENESIS ENERGY, INC., as General Partner Date: November 12, 2003 By: /s/ ROSS A. BENAVIDES --------------------------------- Ross A. Benavides Chief Financial Officer