10-Q 1 0001.txt 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 June 30, 2000 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 -------- -------- This report contains 21 pages 2 GENESIS ENERGY, L.P. Form 10-Q INDEX PART I. FINANCIAL INFORMATION Item 1. Financial Statements Page ---- Consolidated Balance Sheets - June 30, 2000 and December 31, 1999 3 Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2000 and 1999 4 Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2000 and 1999 5 Consolidated Statement of Partners' Capital for the Six Months Ended June 30, 2000 6 Notes to Consolidated Financial Statements 7 Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 14 PART II. OTHER INFORMATION Item 1. Legal Proceedings 21 Item 6. Exhibits and Reports on Form 8-K 21 3 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands)
June 30, December 31, 2000 1999 -------- -------- ASSETS (Unaudited) CURRENT ASSETS Cash and cash equivalents $ 5,674 $ 6,664 Accounts receivable - Trade 447,513 241,529 Related party - 7,030 Inventories 515 404 Insurance receivable for pipeline spill costs 7,000 16,586 Other 10,689 2,504 -------- -------- Total current assets 471,391 274,717 FIXED ASSETS, at cost 116,675 116,332 Less: Accumulated depreciation (25,839) (22,419) -------- -------- Net fixed assets 90,836 93,913 OTHER ASSETS, net of amortization 11,297 11,962 -------- -------- TOTAL ASSETS $573,524 $380,592 ======== ======== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Short-term debt $ 21,000 $ 19,900 Accounts payable - Trade 437,622 251,742 Related party 13,352 1,604 Accrued liabilities 18,157 19,290 -------- -------- Total current liabilities 490,131 292,536 COMMITMENTS AND CONTINGENCIES (Note 8) ADDITIONAL PARTNERSHIP INTERESTS 8,700 3,900 MINORITY INTERESTS 30,428 30,571 PARTNERS' CAPITAL Common unitholders, 8,625 units issued and 8,617 units and 8,620 units outstanding at June 30, 2000 and December 31, 1999, respectively 43,444 52,574 General partner 864 1,051 -------- -------- Subtotal 44,308 53,625 Treasury Units, 8 units and 5 units at June 30, 2000 and December 31, 1999, respectively (43) (40) -------- -------- Total partners' capital 44,265 53,585 -------- -------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $573,524 $380,592 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
4 GENESIS ENERGY, L.P. STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) (Unaudited)
Three Months Ended June 30, Six Months Ended June 30, 2000 1999 2000 1999 ---------- -------- ---------- -------- REVENUES: Gathering and marketing revenues Unrelated parties $1,161,271 $483,404 $2,159,701 $853,777 Related parties 29,820 25,638 29,820 34,892 Pipeline revenues 3,805 4,346 7,218 8,442 ---------- -------- ---------- -------- Total revenues 1,194,896 513,388 2,196,739 897,111 COST OF SALES: Crude costs, unrelated parties 1,124,027 467,287 2,081,523 833,204 Crude costs, related parties 60,598 34,856 95,379 42,273 Field operating costs 3,197 2,958 6,411 5,610 Pipeline operating costs 2,032 1,966 4,085 3,934 ---------- -------- ---------- -------- Total cost of sales 1,189,854 507,067 2,187,398 885,021 ---------- -------- ---------- -------- GROSS MARGIN 5,042 6,321 9,341 12,090 EXPENSES: General and administrative 2,720 3,016 5,376 6,039 Depreciation and amortization 2,035 2,064 4,081 4,112 ---------- -------- ---------- -------- OPERATING INCOME (LOSS) 287 1,241 (116) 1,939 OTHER INCOME (EXPENSE): Interest income 47 39 84 69 Interest expense (354) (306) (702) (516) Gain on asset disposals 32 31 20 900 ---------- -------- ---------- -------- INCOME (LOSS) BEFORE MINORITY INTERESTS 12 1,005 (714) 2,392 Minority interests 2 201 (143) 479 ---------- -------- ---------- -------- NET INCOME (LOSS) $ 10 $ 804 $ (571) $ 1,913 ========== ======== ========== ======== NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED $ - $ 0.09 $ (0.06) $ 0.22 ========== ======== ========== ======== NUMBER OF COMMON UNITS OUTSTANDING 8,623 8,604 8,623 8,604 ========== ======== ========== ======== 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)
Six Months Ended June 30, 2000 1999 --------- -------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (571) $ 1,913 Adjustments to reconcile net income to net cash provided by (used in) operating activities - Depreciation 3,422 3,408 Amortization of intangible assets 659 704 Minority interests equity in earnings (143) 479 Gain on disposals of fixed assets (20) (900) Other noncash charges 1,326 746 Changes in components of working capital - Accounts receivable (198,954) 11,657 Inventories (111) (7,438) Other current assets 1,401 362 Accounts payable 197,628 (14,039) Accrued liabilities (2,365) (2,077) --------- -------- Net cash provided by (used in) operating activities 2,272 (5,185) --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment (365) (1,284) Change in other assets 6 3 Proceeds from sales of assets 40 1,014 --------- -------- Net cash used in investing activities (319) (267) --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Net borrowings under Loan Agreement 1,100 8,700 Distributions to common unitholders (8,625) (8,603) Distributions to general partner (176) (176) Issuance of additional partnership interests 4,800 - Purchase of treasury units (42) - --------- -------- Net cash used in financing activities (2,943) (79) --------- -------- Net decrease in cash and cash equivalents (990) (5,531) Cash and cash equivalents at beginning of period 6,664 7,710 --------- -------- Cash and cash equivalents at end of period $ 5,674 $ 2,179 ========= ======== 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 ------------------------------------- Common General Treasury Unitholders Partner Units Total ------- ------ ---- ------- Partners' capital at December 31, 1999 $52,574 $1,051 $(40) $53,585 Net loss for the six months ended June 30, 2000 (560) (11) - (571) Distributions during the six months ended June 30, 2000 (8,625) (176) - (8,801) Purchase of treasury units - - (42) (42) Issuance of treasury units to Restricted Unit Plan participants - - 39 39 Excess of expense over cost of treasury units issued for Restricted Unit Plan 55 - - 55 ------- ------ ---- ------- Partners' capital at June 30, 2000 $43,444 $ 864 $(43) $44,265 ======= ====== ==== ======= 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 In December 1996, Genesis Energy, L.P. ("GELP") completed an initial public offering of 8.6 million Common Units at $20.625 per unit, representing limited partner interests in GELP of 98%. Genesis Energy, L.L.C. (the "General Partner") serves as general partner of GELP and its operating limited partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P. has two subsidiary limited partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to collectively as GCOLP. The General Partner owns a 2% general partner interest in GELP. Transactions at Formation At the closing of the offering, GELP contributed the net proceeds of the offering to GCOLP in exchange for an 80.01% general partner interest in GCOLP. With the net proceeds of the offering, GCOLP purchased a portion of the crude oil gathering, marketing and pipeline operations of Howell Corporation ("Howell") and made a distribution to Basis Petroleum, Inc. ("Basis") in exchange for its conveyance of a portion of its crude oil gathering and marketing operations. GCOLP issued an aggregate of 2.2 million subordinated limited partner units ("Subordinated OLP Units") to Basis and Howell to obtain the remaining operations. Basis' Subordinated OLP units and its interest in the General Partner were transferred to its then parent, Salomon Smith Barney Holdings Inc. ("Salomon") in May 1997. In February 2000, Salomon acquired Howell's interest in the General Partner. Salomon now owns 100% of the General Partner. Unless the context otherwise requires, the term "the Partnership" hereafter refers to GELP and its operating limited partnership. 2. Basis of Presentation The accompanying consolidated financial statements and related notes present the financial position as of June 30, 2000 and December 31, 1999 for GELP, the results of operations for the three and six months ended June 30, 2000 and 1999, cash flows for the six months ended June 30, 2000 and 1999 and changes in partners' capital for the six months ended June 30, 2000. 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, 1999 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 months ended June 30, 2000 and 1999 was 8,623,000 and 8,604,000, respectively. For the 2000 and 1999 six month periods, the weighted average number of Common Units outstanding was 8,623,000 and 8,604,000, respectively. For this purpose, the 2% General Partner interest is excluded from net income. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. 3. New Accounting Pronouncements In November 1998, the Emerging Issues Task Force (EITF) reached a consensus on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management Activities". This consensus, effective in the first quarter of 1999, requires that "energy trading" contracts be marked-to-market, with gains or losses recognized in current earnings. The Partnership has determined that its activities do not meet the definition in EITF Issue 98-10 of "energy trading" activities and, therefore, is not required to make any change in its accounting, except as 8 EITF 98 -10 relates to written option contracts. EITF 98-10 requires that all written option contracts be marked-to-market. For the three and six months ended June 30, 2000, the Partnership recorded unrealized losses of $0.8 million and $0.6 million, respectively, as a result of marking these contracts to market. These amounts are included in cost of crude in the statement of operations. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", was issued in June 1998. This standard was subsequently amended by SFAS 137 and SFAS 138. This new standard, which the Partnership will be required to adopt for its fiscal year 2001, will change the method of accounting for changes in the fair value of certain derivative instruments by requiring that an entity recognize the derivative at fair value as an asset or liability on its balance sheet. Depending on the purpose of the derivative and the item it is hedging, the changes in fair value of the derivative will be recognized in current earnings or as a component of other comprehensive income in partners' capital. The Partnership is in the process of evaluating the impact that this statement will have on its results of operations and financial position. This new standard could increase volatility in net income and comprehensive income. 4. Business Segment and Customer Information Based on its management approach, the Partnership believes that all of its material operations revolve around the gathering, transportation and marketing of crude oil, and it currently reports its operations, both internally and externally, as a single business segment. No customer accounted for more than 10% of the Partnership's revenues in any period. 5. Credit Resources GCOLP has a Guaranty Facility with Salomon, pursuant to a Master Credit Support Agreement, and a Working Capital Facility with BNP Paribas. GCOLP's obligations under these facilities are secured by its receivables, inventories, general intangibles and cash. Guaranty Facility Salomon is providing a Guaranty Facility through December 31, 2000, in connection with the purchase, sale and exchange of crude oil by GCOLP. The aggregate amount of the Guaranty Facility is limited to $300 million (to be reduced in each case by the amount of any obligation to a third party to the extent that such third party has a prior security interest in the collateral). GCOLP pays a guarantee fee to Salomon of 0.50% of the utilized amount of outstanding guarantees. This fee will increase after June 30, 2000, to 0.75%. An additional fee of 1.00% is paid on any amounts in excess of the $300 million commitment. At June 30, 2000, the aggregate amount of obligations covered by guarantees was $290 million, including $186 million in payable obligations and $104 million of estimated crude oil purchase obligations for July 2000. The Master Credit Support Agreement contains various restrictive and affirmative covenants including (i) restrictions on indebtedness other than (a) pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as defined in the Master Credit Support Agreement) entered into in the ordinary course of business and (c) indebtedness incurred in the ordinary course of business by acquiring and holding receivables to be collected in accordance with customary trade terms, (ii) restrictions on certain liens, investments, guarantees, loans, advances, lines of business, acquisitions, mergers, consolidations and sales of assets and (iii) compliance with certain risk management policies, audit and receivable risk exposure practices and cash management practices as may from time to time be revised or altered by Salomon in its sole discretion. Pursuant to the Master Credit Support Agreement, GCOLP is required to maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b) Consolidated Working Capital of not less than $1 million after exclusion of bank debt from current liabilities, (c) a ratio of its Consolidated Current Liabilities to Consolidated Working Capital plus net property, plant and equipment of not more than 7.5 to 1, (d) a ratio of Consolidated Earnings before Interest, Taxes, Depreciation and Amortization to Consolidated Fixed Charges of at least 1.75 to 1 as of the last day of each fiscal quarter prior to December 31, 1999 and (e) a ratio of Consolidated Total Liabilities to Consolidated Tangible Net Worth of not more than 10.0 to 1 (as such terms are defined in the Master Credit Support Agreement). 9 An Event of Default could result in the termination of the Guaranty Facility at the discretion of Salomon. Significant Events of Default include (a) a default in the payment of (i) any principal on any payment obligation under the Guaranty Facility when due or (ii) interest or fees or other amounts within two business days of the due date, (b) the guaranty exposure amount exceeding the maximum credit support amount on the first day of the month for two consecutive calendar months, (c) failure to perform or otherwise comply with any covenants contained in the Master Credit Support Agreement if such failure continues unremedied for a period of 30 days after written notice thereof and (d) a material misrepresentation in connection with any loan, letter of credit or guarantee issued under the Guaranty Facility. Removal of the General Partner will result in the termination of the Guaranty Facility and the release of all of Salomon's obligations thereunder. The Partnership exceeded the $300 million maximum credit limitation under the Guaranty Facility on May 1 and June 1, 2000, due primarily to the rise in crude oil prices and additional outstanding guarantees. A waiver of the resulting Event of Default was obtained from Salomon. There can be no assurance of the availability or the terms of credit for the Partnership. At this time, Salomon does not intend to provide guarantees or other credit support after the credit support period expires in December 31, 2000. Upon approval of a proposed restructuring discussed in Note 10, Salomon will extend the expiration date of its credit support obligation to the Partnership from December 31, 2000, to December 31, 2001, on the current terms and conditions. If the General Partner is removed without its consent, Salomon's credit support obligations will terminate. In addition, Salomon's obligations under the Master Credit Support Agreement may be transferred or terminated early subject to certain conditions. Management of the Partnership intends to replace the Guaranty Facility with a letter of credit facility with one or more third party lenders prior to December 2000 and has had preliminary discussions with banks about a replacement letter of credit facility. The General Partner may be required to reduce or restrict the Partnership's gathering and marketing activities because of limitations on its ability to obtain credit support and financing for its working capital needs. The General Partner expects that the overall cost of a replacement facility may be substantially greater than what the Partnership is incurring under its existing Master Credit Support Agreement. Any significant decrease in the Partnership's financial strength, regardless of the reason for such decrease, may increase the number of transactions requiring letters of credit or other financial support, make it more difficult for the Partnership to obtain such letters of credit, and/or may increase the cost of obtaining them. This situation could in turn adversely affect the Partnership's ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect the Partnership's profitability and Available Cash. Working Capital Facility On June 6, 2000, GCOLP entered into a credit agreement ("Credit Agreement") with BNP Paribas to replace the Loan Agreement with Bank One. The Credit Agreement provides for loans or letters of credit in the aggregate not to exceed the lesser of $35 million or the Borrowing Base (as defined in the Credit Agreement). The maximum amount the Credit Agreement will be reduced from $35 million to $25 million if BNP Paribas fails to assign loan commitments to other lenders by September 7, 2000. Interest is calculated, at the Partnership's option, by using either LIBOR plus 1.4% or BNP Paribas' prime rate minus 1%. The Credit Agreement expires on the earlier of (a) February 28, 2003 or (b) 30 days prior to the termination of the Master Credit Support Agreement with Salomon. As the Master Credit Support Agreement terminates on December 31, 2000, the Credit Agreement with BNP Paribas will expire on November 30, 2000. See Note 10 for a discussion on the conditions under which Salomon may extend the Master Credit Support Agreement. Should those conditions occur, the Credit Agreement with BNP Paribas will automatically extend to November 30, 2001. The Credit Agreement is collateralized by the accounts receivable, inventory, cash accounts and margin accounts of GCOLP, subject to the terms of an Intercreditor Agreement between BNP Paribas and Salomon. There is no compensating balance requirement under the Credit Agreement. A commitment fee of 0.35% on the available portion of the commitment is provided for in the agreement. Material covenants and restrictions include the following: (a) maintain a Current Ratio (calculated after the exclusion of debt under the Credit Agreement from current liabilities) of 1.0 to 1.0; (b) maintain a Tangible Capital Base (as defined in the Credit Agreement) in GCOLP of not less than $65 million; and (c) maintain a Maximum Leverage Ratio (as defined in the Credit Agreement) of not more than 5.0 to 1.0. Additionally the Credit Agreement imposes restrictions on the ability of GCOLP to sell its assets, incur other indebtedness, create liens and engage in mergers and acquisitions. The 10 Partnership was not in compliance with the covenant regarding a Maximum Leverage Ratio at June 30, 2000. A waiver for the period was obtained from BNP Paribas. At December 31, 1999, and June 30, 2000, the Partnership had $19.9 million and $21.0 million, respectively, of outstanding debt. The Partnership had no letters of credit outstanding at June 30, 2000. At June 30, 2000, $14 million was available to be borrowed under the Credit Agreement. Distributions Generally, GCOLP will distribute 100% of its Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of the cash receipts less cash disbursements of GCOLP adjusted for net changes to reserves. A full definition of Available Cash is set forth in the Partnership Agreement. Distributions of Available Cash to the holders of Subordinated OLP Units are subject to the prior rights of holders of Common Units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2001) and to receive any arrearages in the distribution of the MQD on the Common Units for prior quarters during the subordination period. MQD is $0.50 per unit. Salomon has committed, subject to certain limitations, to provide total cash distribution support with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $17.6 million in exchange for Additional Partnership Interests ("APIs"). Salomon's obligation to provide distribution support will end no later than December 31, 2001 or until the $17.6 million is fully utilized, whichever comes first. Through June 30, 2000, the Partnership utilized $8.7 million of the distribution support from Salomon. On August 14, 2000, the Partnership will utilize an additional $2.6 million of distribution support for the distribution related to the second quarter. After the distribution in August 2000, $11.3 million of distribution support has been utilized and $6.3 million remains available through December 31, 2001, or until such amount is fully utilized, whichever comes first. See Note 10 for additional information regarding a proposed restructuring which could affect distribution support. APIs purchased by Salomon are not entitled to cash distributions or voting rights. The APIs will be redeemed if and to the extent that Available Cash for any future quarter exceeds the amount necessary to distribute the MQD on all Common Units and Subordinated OLP Units and to eliminate any arrearages in the MQD on Common Units for prior periods. In addition, the Partnership Agreement authorizes the General Partner to cause GCOLP to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other GCOLP needs. 6. Transactions with Related Parties Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than those conducted with unaffiliated parties. Sales and Purchases of Crude Oil A summary of sales to and purchases from related parties of crude oil is as follows (in thousands). Six Months Six Months Ended Ended June 30, June 30, 2000 1999 ------- ------- Sales to affiliates $29,820 $34,892 Purchases from affiliates $95,379 $42,273 General and Administrative Services The Partnership does not directly employ any persons to manage or operate its business. Those functions are provided by the General Partner. The Partnership reimburses the General Partner for all direct and indirect costs of 11 these services. Total costs reimbursed to the General Partner by the Partnership were $8,408,000 and $8,542,000 for the six months ended June 30, 2000 and 1999, respectively. Guaranty Facility As discussed in Note 5, Salomon provides a Guaranty Facility to the Partnership. For the six months ended June 30, 2000 and 1999, the Partnership paid Salomon $749,000 and $312,000, respectively, for guarantee fees under the Guaranty Facility. 7. Supplemental Cash Flow Information Cash received by the Partnership for interest was $76,000 and $70,000 for the six months ended June 30, 2000 and 1999, respectively. Payments of interest were $835,000 and $500,000 for the six months ended June 30, 2000 and 1999, respectively. 8. Contingencies The Partnership is subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance. The Partnership's management has made an assessment of its potential environmental exposure and determined that such exposure is not material to its consolidated financial position, results of operations or cash flows. As part of the formation of the Partnership, Basis and Howell agreed to be responsible for certain environmental conditions related to their ownership and operation of their respective assets contributed to the Partnership and for any environmental liabilities which Basis or Howell may have assumed from prior owners of these assets. The Partnership is subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Additionally, litigation involving the Partnership has been filed related to the proposed restructuring. See Note 10. Such matters presently pending are not expected to have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. As part of the formation of the Partnership, Basis and Howell agreed to each retain liability and responsibility for the defense of any future lawsuits arising out of activities conducted by Basis and Howell prior to the formation of the Partnership and have also agreed to cooperate in the defense of such lawsuits. Pipeline Oil Spill On December 20, 1999, the Partnership had a spill of crude oil from its Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi and entered a creek nearby. Some of the oil then flowed into the Leaf River. The Partnership responded to this incident immediately, deploying crews to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill had been substantially cleaned up, with ongoing maintenance and reduced clean-up activity expected to continue for an undetermined period of time. The estimated cost of the spill clean-up is expected to be $18 million. This amount includes estimates for clean-up costs, ongoing maintenance and settlement of potential liabilities to landowners in connection with the spill. The incident was reported to insurers. At June 30, 2000, $15.4 million had been paid to vendors and claimants for spill related costs, and $2.6 million was included in accrued liabilities for estimated future expenditures. Current assets included $3.3 million of expenditures submitted and approved by insurers but not yet reimbursed, $1.1 million for expenditures not yet submitted to insurers and $2.6 million for expenditures not yet incurred or billed to the Partnership. At June 30, 2000, $11.0 million in reimbursements had been received from insurers. As a result of this crude oil spill, certain federal and state regulatory agencies may impose fines and penalties that would not be reimbursed by insurance. At this time, it is not possible to predict whether the Partnership will be fined, the amounts of such fines or whether the governmental agencies would prevail in imposing such fines. 12 The segment of the Mississippi System where the spill occurred has been temporarily shut down and will not be returned to service until regulators give their approval. Regulatory authorities may require specific testing or changes to the pipeline before allowing the Partnership to restart that segment of the system. At this time, it is unknown whether there will be any required testing or changes and the related cost of that testing or changes. If Management of the Partnership determines that the costs of testing or changes are too high, that segment of the system may not be restarted. If this part of the Mississippi System is taken out of service, the net book value of that portion of the pipeline would be written down to its net realizable value, resulting in a non-cash write-off of approximately $6.0 million. Tariff revenues for this segment of the system in the year 1999 were $0.6 million. Crude Oil Contamination In February and March 2000, the Partnership purchased crude oil from a third party that was subsequently determined to contain organic chlorides. These barrels were delivered into the Partnership's Texas pipeline system and potentially contaminated 24,000 barrels of oil held in storage and 44,000 barrels of oil in the pipeline. The north end of the Texas pipeline system has been temporarily shut down but is expected to be operational by the end of the third quarter of 2000. As of June 30, 2000, the estimated volume of crude that was potentially contaminated had been reduced to 21,000 barrels. The Partnership has accrued costs associated with transportation, testing and consulting in the amount of $188,000, of which $32,000 has been paid at June 30, 2000. The potentially contaminated barrels are reflected in inventory at their cost of approximately $0.6 million. The Partnership has recorded a receivable for $188,000 to reflect the expected recovery of the accrued costs from the third party. The third party has provided the Partnership with evidence that it has sufficient resources to cover the total expected damages incurred by the Partnership. Management of the Partnership believes that it will recover any damages incurred from the third party. 9. Distributions On July 14, 2000, the Board of Directors of the General Partner declared a cash distribution of $0.50 per Unit for the quarter ended June 30, 2000. The distribution will be paid August 14, 2000, to the General Partner and all Common Unitholders of record as of the close of business on July 31, 2000. The Subordinated OLP Unitholders will not receive a distribution for the quarter. This distribution will be paid utilizing approximately $1.8 million cash available from the Partnership and $2.6 million cash provided by Salomon pursuant to Salomon's Distribution Support Agreement. 10. Proposed Restructuring On May 10, 2000, the Partnership announced that based on the recommendation of the Special Committee appointed by the General Partner, the General Partner and the Board of Directors of the General Partner of the Partnership unanimously approved a financial restructuring of the Partnership. The proposal for a financial restructuring of the Partnership is subject to approval by holders of a majority of the Partnership's outstanding public common units. Assuming unitholder approval, the proposed restructuring is expected to be effective beginning with distributions for the third quarter of 2000. Under the terms of the restructuring, the partnership agreement of GCOLP will be amended to: - eliminate without the payment of any consideration all of the outstanding subordinated limited partner units in our operating partnership; - terminate the subordination period and, as a result, eliminate the requirement that the common limited partnership units accrue arrearages; - eliminate without the payment of any consideration all of the outstanding additional limited partner interests, or APIs, issued to Salomon in exchange for its distribution support and, as a result, eliminate our obligation to redeem the APIs issued to Salomon in exchange for its distribution support; 13 - reduce the quarterly distribution from the current $0.50 per unit to a targeted $0.20 per unit; and - reduce the respective thresholds that must be achieved before the general partner is entitled to incentive distributions from the current threshold levels of $0.55, $0.635 and $0.825 to the new threshold levels of $0.25, $0.28 and $0.33 per unit. If the proposal is approved: - Salomon will contribute to the operating partnership the unused distribution support expected to be $6.3 million. After payment of transaction costs associated with the restructuring estimated at $1.3 million, we will then declare a special distribution in the aggregate amount of $5.0 million, or $0.58 per unit. - Salomon will extend the expiration date of its credit support obligation to the partnership from December 31, 2000 to December 31, 2001 on the current terms and conditions. In connection with the proposal for restructuring, the Partnership is preparing a proxy statement to be mailed to all of the Partnership's public unitholders that will contain a more detailed description of the proposal. On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner interests in the Partnership, filed a putative class action complaint in the Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring and seeking damages. Defendants named in the complaint include the Partnership, Genesis Energy L.L.C., members of the board of directors of Genesis Energy, L.L.C., and the owner of Genesis Energy L.L.C. The plaintiff alleges numerous breaches of the duties of care and loyalty owed by the defendants to the purported class in connection with making a proposal for restructuring. Management of the Partnership believes that the complaint is without merit and intends to vigorously defend the action. 14 GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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, Mississippi, New Mexico, Kansas and Oklahoma. The following review of the results of operations and financial condition should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Results of Operations Selected financial data for this discussion of the results of operations follows, in thousands, except barrels per day.
Three Months Ended June 30, Six Months Ended June 30, 2000 1999 2000 1999 -------- -------- -------- -------- Gross margin Gathering and marketing $ 3,269 $ 3,941 $ 6,208 $ 7,582 Pipeline $ 1,773 $ 2,380 $ 3,133 $ 4,508 General and administrative expenses$ 2,720 $ 3,016 $ 5,376 $ 6,039 Depreciation and amortization $ 2,035 $ 2,064 $ 4,081 $ 4,112 Operating income (loss) $ 287 $ 1,241 $ (116) $ 1,939 Interest income (expense), net $ (307) $ (267) $ (618) $ (447) Barrels per day Wellhead 101,702 88,985 101,977 88,614 Bulk and exchange 361,973 263,187 325,775 268,026 Pipeline 92,493 95,590 90,333 92,190
Gross margins from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels of crude oil do not necessarily bear a relationship to gross margin because absolute price levels normally impact revenues and cost of sales by equivalent amounts. As a result, the impact of period-to-period price variations on revenues and cost of sales generally are not meaningful in analyzing the variations in gross margins, and such changes are not addressed in the following discussion. Pipeline gross margins are primarily a function of the level of throughput and storage activity and are generated by the difference between the regulated published tariff and the fixed and variable costs of operating the pipeline. Changes in revenues, volumes and pipeline operating costs, therefore, are relevant to the analysis of financial results of the Partnership's pipeline operations. The price level of crude oil impacts gathering and marketing and pipeline gross margins to the extent that oil producers adjust production levels. Short- term and long-term price trends impact the amount of cash flow that producers have available to maintain existing production and to invest in new reserves, which in turn impacts the amount of supply that is available to be gathered and marketed by the Partnership and its competitors. Six Months Ended June 30, 2000 Compared with Six Months Ended June 30, 1999 Gross margin from gathering and marketing activities was $6.2 million for the six months ended June 30, 2000, as compared to $7.6 million for the six months ended June 30, 1999. The decrease of $1.4 million represents the net effect of several factors. Wellhead, bulk and exchange purchase volumes for the six months ended June 30, 2000, increased 20 percent from the same period in 1999. This rise resulted in a $1.5 million increase in gathering and marketing gross 15 margins. The gain was partially offset by a 9 percent decline in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, which reduced gross margin by $0.8 million. Also contributing to the decline in gross margin were a $0.6 million unrealized loss on written option contracts (see Note 3 to the financial statements), a $0.7 million increase in the cost of credit and a $0.8 million increase in field operating costs. The $0.7 million increase in credit costs is a function of the increase in purchase volumes and an 88 percent increase in the absolute price level of crude oil. The increase in field operating costs was primarily from a $0.3 million increase in payroll and benefits costs and a $0.4 million increase in fuel costs. Pipeline gross margin declined $1.4 million, from $4.5 million for the six month period in 1999 to $3.1 million for the six month period in 2000. Average tariff revenues declined approximately $0.05 per barrel, which reduced gross margin by $0.8 million. Additionally, revenues for the 1999 period included tank storage fees of $0.6 million. General and administrative expenses decreased $0.7 million between the 2000 and 1999 six month periods. This decline is attributable to decreases in the following areas: $0.2 million in salary and benefits, $0.1 million in restricted unit expense and $0.1 million each in professional services and travel and entertainment. Additionally, the 1999 six month period included costs related to the Year 2000 remediation totaling $0.2 million. Depreciation and amortization was flat between the two six month periods. The Partnership had no material property acquisitions or dispositions that would create a material fluctuation in depreciation. In the 2000 six month period, the Partnership incurred net interest expense of $0.6 million. In the 1999 period, the Partnership incurred net interest expense of $0.4 million. The increase in interest cost in 2000 was due to the combination of higher market interest rates and higher interest rates under the BNP Paribas Working Capital Facility than under the prior facility. Additionally, average daily outstanding debt during the 2000 period was $2.6 million greater. Three Months Ended June 30, 2000 Compared with Three Months Ended June 30, 1999 Gross margin from gathering and marketing activities was $3.3 million for the three months ended June 30, 2000, as compared to $3.9 million for the three months ended June 30, 1999. The decrease of $0.6 million represents the net effect of several factors. Wellhead, bulk and exchange purchase volumes for the three months ended June 30, 2000, increased 32 percent from the same period in 1999. This rise resulted in a $1.3 million increase in gathering and marketing gross margins. The gain was partially offset by a 9 percent decline in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, which reduced gross margin by $0.5 million. Also contributing to the decline in gross margin were a $0.8 million unrealized loss on written option contracts (see Note 3 to the financial statements), a $0.3 million increase in the cost of credit and a $0.2 million increase in field operating costs. The $0.3 million increase in credit costs is a function of the increase in purchase volumes and a 65 percent increase in the absolute price level of crude oil. The increase in field operating costs was primarily from increases in payroll and benefits costs and fuel costs. Pipeline gross margin was $1.8 million for the three months ended June 30, 2000, as compared to $2.4 million for the three months ended June 30, 1999. The $0.6 million decrease in gross margin can be primarily attributed to a $0.03 per barrel decline in average tariff revenues, which reduced gross margin by $0.3 million, and a 4 percent decline in throughput, which resulted in a $0.2 million decline in gross margin. Additionally, pipeline operating costs increased $0.1 million. General and administrative expenses declined $0.3 million in the three months ended June 30, 2000 as compared to the same period in 1999. The primary factors in this decline were a decrease in salaries and benefits, restricted unit expense and Year 2000 remediation costs of $0.1 million each. Interest costs were slightly higher in the 2000 quarter due primarily to higher interest rates. 16 Hedging Activities Genesis routinely utilizes forward contracts, swaps, options and futures contracts in an effort to minimize the impact of market fluctuations on inventories and contractual commitments. Gains and losses on forward contracts, swaps and future contracts used to hedge future contract purchases of unpriced crude oil, where firm commitments to sell are required prior to establishment of the purchase price, are deferred until the margin from the hedged item is recognized. The Partnership recognized net losses of $1.5 million and $1.2 million for the six months and three months ended June 30, 2000, respectively, and net gains of $2.0 million and $0.9 million for the six and three months ended June 30, 1999, respectively, related to its hedging activity. Liquidity and Capital Resources Cash Flows Cash flows provided by operating activities were $2.3 million for the six months ended June 30, 2000. In the 1999 six-month period, cash flows utilized in operating activities were $5.2 million. The change between the two periods results primarily from an increase in inventories in the 1999 period and variations in the timing of payment of crude purchase obligations. For the six months ended June 30, 2000 and 1999, cash flows utilized in investing activities were $0.3 million. In 2000, the Partnership expended $0.4 million for property and equipment additions related primarily to pipeline operations. In 1999, the Partnership added $1.3 million of assets, primarily for pipeline operations, and received proceeds of $1.0 million from the sale of surplus tractors and trailers. Cash flows used in financing activities by the Partnership during the first six months of 2000 totaled $2.9 million. Distributions paid to the common unitholders and the general partner totaled $8.8 million. The Partnership borrowed $1.1 million under its Working Capital Facility and received $4.8 million from the issuance of APIs to Salomon. In the 1999 period, cash flows used in financing activities totaled $0.1 million. The Partnership obtained funds by borrowing $8.7 million. Distributions to the common unitholders and the general partner totaled $8.8 million. Working Capital and Credit Resources As discussed in Note 5 of the Notes to Condensed Consolidated Financial Statements, the Partnership has a Guaranty Facility with Salomon through December 31, 2000, and a Credit Agreement with BNP Paribas for working capital purposes that extends through November 30, 2000. Both of these agreements may be extended under certain conditions as discussed below under "Proposed Restructuring". If the General Partner is removed without its consent, Salomon's credit support obligations will terminate. In addition, Salomon's obligations under the Master Credit Support Agreement may be transferred or terminated early subject to certain conditions. At June 30, 2000, the Partnership's consolidated balance sheet reflected a working capital deficit of $18.7 million. This working capital deficit combined with the short-term nature of both the Guaranty Facility with Salomon and the Credit Agreement with BNP Paribas could have a negative impact on the Partnership. Some counterparties use the balance sheet and the nature of available credit support as a basis for determining credit support demanded from the Partnership as a condition of doing business. Increased demands for credit support beyond the maximum credit limitations may adversely affect the Partnership's ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect the Partnership's profitability and Available Cash. Management of the Partnership intends to replace the Guaranty Facility and Credit Agreement with a working capital letter of credit facility with one or more third party lenders prior to November 2000. The General Partner expects that the annual cost of a replacement facility would increase by approximately $3.3 million. Increased credit needs and higher credit costs could adversely affect the Partnership's ability to maintain or increase the level of its purchasing and marketing activities. Profitability and Available Cash for distributions could be adversely impacted as well. 17 The Partnership will pay a distribution of $0.50 per Unit for the three months ended June 30, 2000, on August 14, 2000 to the General Partner and all Common Unitholders of record as of the close of business on July 31, 2000. The subordinated OLP Unitholders will not receive a distribution for that period. This distribution will be paid utilizing approximately $1.8 million of cash available from the Partnership and $2.6 million of cash provided by Salomon, pursuant to Salomon's distribution support obligation. Under the Distribution Support Agreement, Salomon has committed, subject to certain limitations, to provide cash distribution support, with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $17.6 million in exchange for APIs. Salomon's obligation to purchase APIs will end no later than December 31, 2001, or when the distribution support has been fully utilized, whichever comes first. . After the distribution in August 2000, $11.3 million of distribution support has been utilized and $6.3 million remains available through December 31, 2001, or until such amount is fully utilized, whichever comes first. The Distribution Support Agreement will be terminated if the proposed restructuring discussed below is approved by a majority of the Partnership's unitholders. Proposed Restructuring On May 10, 2000, the Partnership announced that based on the recommendation of the Special Committee appointed by the General Partner, the General Partner and the Board of Directors of the General Partner of the Partnership unanimously approved a financial restructuring of the Partnership. The proposal for a financial restructuring of the Partnership is subject to approval by holders of a majority of the Partnership's outstanding public common units. Assuming unitholder approval, the proposed restructuring is expected to be effective beginning with distributions for the third quarter of 2000. Under the terms of the restructuring, the partnership agreement of GCOLP will be amended to: - eliminate without the payment of any consideration all of the outstanding subordinated limited partner units in our operating partnership; - terminate the subordination period and, as a result, eliminate the requirement that the common limited partnership units accrue arrearages; - eliminate without the payment of any consideration all of the outstanding additional limited partner interests, or APIs, issued to Salomon in exchange for its distribution support and, as a result, eliminate our obligation to redeem the APIs issued to Salomon in exchange for its distribution support; - reduce the quarterly distribution from the current $0.50 per unit to a targeted $0.20 per unit; and - reduce the respective thresholds that must be achieved before the general partner is entitled to incentive distributions from the current threshold levels of $0.55, $0.635 and $0.825 to the new threshold levels of $0.25, $0.28 and $0.33 per unit. If the proposal is approved: - Salomon will contribute to the operating partnership the unused distribution support expected to be $6.3 million. After payment of transaction costs associated with the restructuring estimated at $1.3 million, we will then declare a special distribution in the aggregate amount of $5.0 million or $0.58 per unit. - Salomon will extend the expiration date of its credit support obligation to the partnership from December 31, 2000 to December 31, 2001 on the current terms and conditions. In connection with the proposal for restructuring, the Partnership is preparing a proxy statement to be mailed to all of the Partnership's public unitholders that will contain a more detailed description of the proposal. 18 Crude Oil Spill On December 20, 1999, the Partnership had a spill of crude oil from its Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi and entered a creek nearby. Some of the oil then flowed into the Leaf River. The Partnership responded to this incident immediately, deploying crews to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill had been substantially cleaned up, with ongoing maintenance and reduced clean-up activity expected to continue for an undetermined period of time. The estimated cost of the spill clean-up is expected to be $18 million. This amount includes estimates for clean-up costs, ongoing maintenance and settlement of potential liabilities to landowners in connection with the spill. The incident was reported to insurers. At June 30, 2000, $15.4 million had been paid to vendors and claimants for spill related costs, and $2.6 million was included in accrued liabilities for estimated future expenditures. Current assets included $3.3 million of expenditures submitted and approved by insurers but not yet reimbursed, $1.1 million for expenditures not yet submitted to insurers and $2.6 million for expenditures not yet incurred or billed to the Partnership. At June 30, 2000, $11.0 million in reimbursements had been received from insurers. As a result of this crude oil spill, certain federal and state regulatory agencies may impose fines and penalties that would not be reimbursed by insurance. At this time, it is not possible to predict whether the Partnership will be fined, the amounts of such fines or whether the governmental agencies would prevail in imposing such fines. The segment of the Mississippi System where the spill occurred has been temporarily shut down and will not be returned to service until regulators give their approval. Regulatory authorities may require specific testing or changes to the pipeline before allowing the Partnership to restart that segment of the system. At this time, it is unknown whether there will be any required testing or changes and the related cost of that testing or changes. If Management of the Partnership determines that the costs of testing or changes are too high, that segment of the system may not be restarted. If this part of the Mississippi System is taken out of service, the net book value of that portion of the pipeline would be written down to its net realizable value, resulting in a non-cash write-off of approximately $6.0 million. Tariff revenues for this segment of the system in the year 1999 were $0.6 million. Crude Oil Contamination In February and March 2000, the Partnership purchased crude oil from a third party that was subsequently determined to contain organic chlorides. These barrels were delivered into the Partnership's Texas pipeline system and potentially contaminated 24,000 barrels of oil held in storage and 44,000 barrels of oil in the pipeline. The north end of the Texas pipeline system has been temporarily shut down but is expected to be operational by the end of the third quarter of 2000. As of June 30, 2000, the estimated volume of crude that was potentially contaminated had been reduced to 21,000 barrels. The Partnership has accrued costs associated with transportation, testing and consulting in the amount of $188,000, of which $32,000 has been paid at June 30, 2000. The potentially contaminated barrels are reflected in inventory at their cost of approximately $0.6 million. The Partnership has recorded a receivable for $188,000 to reflect the expected recovery of the accrued costs from the third party. The third party has provided the Partnership with evidence that it has sufficient resources to cover the total expected damages incurred by the Partnership. Management of the Partnership believes that it will recover any damages incurred from the third party. Current Business Conditions Changes in the price of crude oil impact gathering and marketing and pipeline gross margins to the extent that oil producers adjust production levels. Short-term and long-term price trends impact the amount of cash flow that producers have available to maintain existing production and to invest in new reserves, which in turn impacts the amount of crude oil that is available to be gathered and marketed by the Partnership and its competitors. 19 Although crude oil prices have increased from $12 per barrel in January 1999 to nearly $32 per barrel in June 2000, U.S. onshore crude oil production volumes have not improved. Further, producers appear to be responding cautiously to the oil price increase and are focusing more on drilling for natural gas. This change is clearly demonstrated by the Baker Hughes North American Rotary Rig Count for 1997 to 2000. Baker Hughes North American Rotary Rig Count Average Number of Rigs Drilling For Crude Oil Year Oil Gas Price per bbl* ---- --- --- ------------- 1997 376 566 $20.60 1998 264 560 $14.40 1999 128 496 $19.25 2000 177 630 $28.80 * Annual average price for 1997 through 1999 and six month average for 2000 for West Texas Intermediate at Cushing, Oklahoma Based on the limited improvement in the number of rigs drilling for oil, management of the General Partner believes that oil production in its primary areas of operation is likely to continue to decrease. Although there has been some increase since January 1999 in the number of drilling and workover rigs being utilized in the Partnership's primary areas of operation, management of the General Partner believes that this activity is more likely to have the effect of reducing the rate of decline rather than meaningfully increasing wellhead volumes in its operating areas in 2000. The Partnership's improved volumes in the first half of 2000 compared to the same period of 1999 were primarily due to obtaining existing production by paying higher prices for the production than the previous purchaser. Increased volumes obtained through competition based on price for existing production generally result in incrementally lower margins per barrel. As crude oil prices rise, the Partnership's utilization of, and cost of credit under, the Guaranty Facility increases with respect to the same volume of business. The General Partner has taken steps to reduce or restrict the Partnership's gathering and marketing activities due to the $300 million limit of the Guaranty Facility. Additionally, as prices rise, the Partnership may have to increase the amount of its Credit Agreement in order to have funds available to meet margin calls on the NYMEX and to fund inventory purchases. No assurances can be made that the Partnership would be able to increase the size of its Credit Agreement or that changes to the terms of such increased Credit Agreement would not have a material impact on the results of operations or cash flows of the Partnership. Forward Looking Statements The statements in this Report on Form 10-Q that are not historical information are forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Partnership believes that its expectations regarding future events are based on reasonable assumptions, it can give no assurance that its goals will be achieved or that its expectations regarding future developments will prove to be correct. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include, but are not limited to, changes in regulations, the Partnership's success in obtaining additional lease barrels, changes in crude oil production volumes (both world-wide as well as in areas in which the Partnership has operations), developments relating to possible acquisitions or business combination opportunities, volatility of crude oil prices and grade differentials, the success of the Partnership's risk management activities, credit requirements by counterparties of the Partnership, the Partnership's ability to replace its credit support from Salomon with a bank facility and to replace the working capital facility from Paribas with another facility, any requirements for testing or changes to the Mississippi System as a result of the oil spill that occurred there in December 1999 and conditions of the capital markets and equity markets during 19 the periods covered by the forward looking statements. All subsequent written or oral forward looking statements attributable to the Partnership or persons acting on behalf of the Partnership are expressly qualified in their entirety by the foregoing cautionary statements. 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. The Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based futures contracts, forward contracts, swap agreements and option contracts to hedge its exposure to these market price fluctuations. Management believes the hedging program has been effective in minimizing overall price risk. At June 30, 2000, the Partnership used futures and forward contracts in its hedging program with the latest contract being settled in July 2002. Information about these contracts is contained in the table set forth below. Sell (Short) Buy (Long) Contracts Contracts -------- -------- Crude Oil Inventory: Volume (1,000 bbls) 7 Carrying value (in thousands) $ 107 Fair value (in thousands) $ 107 Commodity Futures Contracts Contract volumes (1,000 bbls) 12,724 14,267 Weighted average price per bbl $ 29.11 $ 28.43 Contract value (in thousands) $370,366 $405,565 Fair value (in thousands) $400,760 $445,068 Commodity Forward Contracts: Contract volumes (1,000 bbls) 6,869 4,895 Weighted average price per bbl $ 30.57 $ 30.59 Contract value (in thousands) $209,991 $149,758 Fair value (in thousands) $221,653 $158,541 Commodity Option Contracts: Contract volumes (1,000 bbls) 11,430 Weighted average strike price per bbl $ 2.49 Contract value (in thousands) $ 3,278 Fair value (in thousands) $ 3,906 The table above presents notional amounts in barrels, the weighted average contract price, total contract amount in U.S. dollars and total fair value amount in U.S. dollars. Fair values were determined by using the notional amount in barrels multiplied by the June 30, 2000 closing prices of the applicable NYMEX futures contract adjusted for location and grade differentials, as necessary. PART II. OTHER INFORMATION Item 1. Legal Proceedings See Part I. Item 1. Note 8 to the Condensed Consolidated Financial Statements entitled "Contingencies", which is incorporated herein by reference. 21 Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. Exhibit 10 Credit Agreement dated as of June 6, 2000 by and between Genesis Crude Oil, L.P. and BNP Paribas Exhibit 27 Financial Data Schedule (b) Reports on Form 8-K. A report on Form 8-K was filed on May 12, 2000, announcing the proposed restructuring of the Partnership. 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, L.L.C., as General Partner Date: August 11, 2000 By: /s/ Ross A. Benavides ---------------------------- Ross A. Benavides Chief Financial Officer