-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WOcruYkAu0PM0SgzEsZOkvNjE+hzut41NJPAdC16UMixdY1nAiu+1BTV2sRt1ZPJ MJFBEgRBMq68Q04xnIdBDQ== 0000950129-05-004914.txt : 20050509 0000950129-05-004914.hdr.sgml : 20050509 20050509112841 ACCESSION NUMBER: 0000950129-05-004914 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20050331 FILED AS OF DATE: 20050509 DATE AS OF CHANGE: 20050509 FILER: COMPANY DATA: COMPANY CONFORMED NAME: GENESIS ENERGY LP CENTRAL INDEX KEY: 0001022321 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM BULK STATIONS & TERMINALS [5171] IRS NUMBER: 760513049 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12295 FILM NUMBER: 05810279 BUSINESS ADDRESS: STREET 1: 500 DALLAS SUITE 2500 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138602500 MAIL ADDRESS: STREET 1: 500 DALLAS SUITE 2500 CITY: HOUSTON STATE: TX ZIP: 77002 10-Q 1 h25224e10vq.txt GENESIS ENERGY, L.P.- MARCH 31, 2005 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2005 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 by Rule 12b-2 of the Exchange Act.) Yes [X] No [ ] ================================================================================ This report contains 31 pages GENESIS ENERGY, L.P. FORM 10-Q INDEX
PART I. FINANCIAL INFORMATION Item 1. Financial Statements Page ---- Consolidated Balance Sheets - March 31, 2005 and December 31, 2004........................ 3 Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004.. 4 Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004.. 5 Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2005..... 6 Notes to Consolidated Financial Statements................................................ 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 16 Item 3. Quantitative and Qualitative Disclosures about Market Risk................................ 30 Item 4. Controls and Procedures................................................................... 30 PART II. OTHER INFORMATION Item 1. Legal Proceedings......................................................................... 31 Item 6. Exhibits.................................................................................. 31 SIGNATURES ....................................................................................... 31
-2- GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands) (Unaudited)
March 31, December 31, 2005 2004 ---------- ------------ ASSETS CURRENT ASSETS Cash and cash equivalents ....................................... $ 3,131 $ 2,078 Accounts receivable: Trade ........................................................ 89,339 68,737 Related party ................................................ 1,153 584 Inventories ..................................................... 1,797 1,866 Net investment in direct financing leases, net of unearned income - current portion ...................................... 505 318 Insurance receivable ............................................ 2,097 2,125 Other ........................................................... 1,240 1,688 --------- --------- Total current assets ......................................... 99,262 77,396 FIXED ASSETS, at cost .............................................. 68,094 73,023 Less: Accumulated depreciation .................................. (34,569) (39,237) --------- --------- Net fixed assets ............................................. 33,525 33,786 NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income .. 6,343 4,247 CO2 ASSETS, net of amortization .................................... 25,708 26,344 OTHER ASSETS, net of amortization .................................. 1,819 1,381 --------- --------- TOTAL ASSETS ....................................................... $ 166,657 $ 143,154 ========= ========= LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable - Trade ........................................................ $ 94,626 $ 74,176 Related party ................................................ 624 1,239 Accrued liabilities ............................................. 6,651 6,523 --------- --------- Total current liabilities .................................... 101,901 81,938 LONG-TERM DEBT ..................................................... 17,500 15,300 OTHER LONG-TERM LIABILITIES ........................................ 156 160 COMMITMENTS AND CONTINGENCIES (Note 11) MINORITY INTERESTS ................................................. 517 517 PARTNERS' CAPITAL Common unitholders, 9,314 units issued and outstanding .......... 45,644 44,326 General partner ................................................. 939 913 --------- --------- Total partners' capital ...................................... 46,583 45,239 --------- --------- TOTAL LIABILITIES AND PARTNERS' CAPITAL ............................ $ 166,657 $ 143,154 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. -3- GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) (Unaudited)
Three Months Ended March 31, 2005 2004 ------------ -------------- REVENUES: Crude oil gathering and marketing: Unrelated parties (including revenues from buy/sell arrangements of $85,842 in 2005 and $58,796 in 2004, respectively) ................... $ 246,824 $ 192,996 Related parties ......................................................... 184 - Pipeline transportation, including natural gas sales: Unrelated parties ....................................................... 6,201 4,085 Related parties ......................................................... 1,111 - CO2 revenues ............................................................... 2,280 1,831 --------- --------- Total revenues ....................................................... 256,600 198,912 COST AND EXPENSES: Crude oil costs: Unrelated parties (including crude oil costs from buy/sell arrangements of $86,145 in 2005 and $58,581 in 2004, respectively) ................ 241,811 165,972 Related parties ......................................................... 477 22,975 Field operating ......................................................... 3,832 3,043 Pipeline transportation costs: Pipeline operating costs ................................................ 2,233 2,232 Natural gas purchases ................................................... 2,636 - CO2 marketing costs: Transportation costs - related party .................................... 717 566 Other costs ............................................................. 38 25 General and administrative ................................................. 858 3,164 Depreciation and amortization .............................................. 1,526 1,547 Net gain on disposal of surplus assets ..................................... (371) - --------- --------- OPERATING INCOME (LOSS) ....................................................... 2,843 (612) OTHER INCOME (EXPENSE): Interest income ............................................................ 6 24 Interest expense ........................................................... (361) (194) --------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS ...................................... 2,488 (782) Income (loss) from operations of discontinued Texas System .................... 282 (223) --------- --------- NET INCOME (LOSS) ............................................................. $ 2,770 $ (1,005) ========= ========= NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED: Income (loss) from continuing operations ................................... $ 0.26 $ (0.09) Income (loss) from discontinued operations ................................. 0.03 (0.02) --------- --------- NET INCOME (LOSS) .......................................................... $ 0.29 $ (0.11) ========= ========= WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING ........................... 9,314 9,314 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. -4- GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)
Three Months Ended March 31, 2005 2004 ------------ --------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ............................................................ $ 2,770 $ (1,005) Adjustments to reconcile net income (loss) to net cash provided by operating activities - Depreciation .............................................................. 890 1,024 Amortization of CO2 contracts ............................................. 636 523 Amortization of credit facility issuance costs ............................ 93 93 Amortization of unearned income on direct financing leases ................ (177) - Payments received under direct financing leases ........................... 297 - Change in fair value of derivatives ....................................... 9 - Gain on asset disposals ................................................... (653) - Other non-cash charges .................................................... (1,329) 1,104 Changes in components of working capital - Accounts receivable .................................................... (21,171) (7,674) Inventories ............................................................ 159 306 Other current assets ................................................... 476 6,818 Accounts payable ....................................................... 19,171 7,726 Accrued liabilities .................................................... 1,368 (12,518) -------- -------- Net cash provided by (used in) operating activities ............................ 2,539 (3,603) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment .......................................... (3,597) (400) Proceeds from sale of assets ................................................. 1,319 - Other, net ................................................................... (546) - -------- -------- Net cash used in investing activities .......................................... (2,824) (400) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Bank borrowings of debt ...................................................... 2,200 2,900 Other, net ................................................................... 564 - Distributions to common unitholders .......................................... (1,397) (1,397) Distributions to General Partner ............................................. (29) (29) -------- -------- Net cash provided by financing activities ...................................... 1,338 1,474 -------- -------- Net increase (decrease) in cash and cash equivalents ........................... 1,053 (2,529) Cash and cash equivalents at beginning of year ................................. 2,078 2,869 -------- -------- Cash and cash equivalents at end of period ..................................... $ 3,131 $ 340 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. -5- GENESIS ENERGY, L.P. CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (In thousands) (Unaudited)
Partners' Capital -------------------------------------------- Number of Common Common General Units Unitholders Partner Total --------- ----------- --------- --------- Partners' capital at January 1, 2005 .................. 9,314 $ 44,326 $ 913 $ 45,239 Net income for the three months ended March 31, 2005... - 2,715 55 2,770 Distributions to partners during the three months ended March 31, 2005 ................................ - (1,397) (29) (1,426) ----- -------- -------- -------- Partners' capital at March 31, 2005 ................... 9,314 $ 45,644 $ 939 $ 46,583 ===== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. -6- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Organization Genesis Energy, L.P. (GELP or the Partnership) is a publicly traded Delaware limited partnership engaged in gathering, marketing and transportation of crude oil and natural gas and wholesale marketing of carbon dioxide (CO2). We have 9.3 million common units outstanding, representing limited partner interests in us of 98%. Our general partner is Genesis Energy, Inc. which owns a 2% general partner interest in us. The general partner is owned by Denbury Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. Our general partner holds 0.7 million of our common units (7.4%). Genesis Crude Oil, L.P. is our operating limited partnership and is owned 99.99% by us and 0.01% by our general partner. Genesis Crude Oil, L.P. has five subsidiary partnerships: Genesis Pipeline Texas, L.P., Genesis Pipeline USA, L.P., Genesis CO2 Pipeline, L.P., Genesis Natural Gas Pipeline, L.P. and Genesis Syngas Investments, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to as GCOLP. Basis of Presentation The accompanying financial statements and related notes present our consolidated financial position as of March 31, 2005 and December 31, 2004 and our results of operations, cash flows and changes in partners' capital for the three months ended March 31, 2005 and 2004. The financial statements included herein have been prepared by us 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, we believe 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 our Annual Report on Form 10-K for the year ended December 31, 2004 filed with the SEC. All significant intercompany transactions have been eliminated. We have not included a provision for income taxes in our consolidated financial statements; as such income will be taxable directly to the partners holding partnership interests in the Partnership. 2. NEW ACCOUNTING PRONOUNCEMENTS The Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) is currently considering the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As part of Issue 04-13, the EITF is considering a requirement that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the income statement. Should this requirement be adopted, our reported crude oil gathering and marketing revenues from unrelated parties for the three months ended March 31, 2005 would be reduced by $85.8 million to $161.0 million and our reported crude oil costs from unrelated parties for the three months ended March 31, 2005, would be reduced by $86.1 million to $155.7 million. In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised December 2004), "Share-Based Payments" (SFAS 123(R)). This statement replaces SFAS No. 123 and requires that compensation costs related to share-based payment transactions be recognized in the financial statements. This statement is effective for public entities as of the first interim or annual reporting period of the first fiscal year beginning on or after June 15, 2005. We plan to adopt SFAS 123(R) in the first quarter of 2006. The adoption of this statement will require that the compensation cost associated with our stock appreciation rights plan be re-measured each reporting period based on the fair value of the rights. Before the adoption of SFAS 123 (R), we have accounted for the stock appreciation rights in accordance with FASB Interpretation No. 28 "Accounting for Stock -7- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Appreciation Rights and Other Variable Stock Option or Award Plans" which required that the liability under the plan be measured at each balance sheet date based on the market price of our Common Units at that date. Under SFAS 123(R), the liability will be calculated using a fair value method that will take into consideration the expected future value of the rights at their expected exercise dates. We are currently evaluating what effect SFAS 123(R) will have on our financial statements, but at this time, we do not believe that the adoption of this statement will have a material effect on our financial position, results of operations or cash flows. In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143" (FIN 47). FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, "Accounting for Asset Retirement Obligations", refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation and emphasizes that uncertainty about the timing or method of settlement of the obligation should be factored into the calculation of the fair value of the obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005. We are currently evaluating what effect FIN 47 will have on our financial statements, but at this time, we do not believe that the adoption of FIN 47 will have a material effect on our financial position, results of operations or cash flows. 3. NET INVESTMENT IN DIRECT FINANCING LEASES In 2004, we constructed a segment of crude oil pipeline and a CO2 pipeline in Mississippi. Denbury pays us a minimum payment each month for the right to use these pipelines. Both of these arrangements are accounted for as direct financing leases. In the first quarter of 2005, we completed another crude oil pipeline segment to move crude oil from a Denbury field to our Mississippi System. Denbury pays us a minimum payment each month for the right to use this pipeline. This arrangement is also being accounted for as a direct financing lease. At March 31, 2005, the components of the net investment in direct financing leases were as follows (in thousands): Total minimum lease payments to be received .................. $ 10,300 Estimated residual values of leased property (unguaranteed) .. 1,287 Less: Unearned income ........................................ (4,739) -------- Net investment in direct financing leases .................... $ 6,848 ========
At March 31, 2005, minimum lease payments to be received for each of the five succeeding fiscal years are $1.2 million per year. 4. DEBT At March 31, 2005, we had $5.0 million outstanding under the working capital portion and $12.5 million outstanding under the acquisition portion of our Credit Facility. At March 31, 2005, the weighted average interest rate on this debt was 7.5%. Due to the revolving nature of loans under both portions of the Credit Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 1, 2008. At March 31, 2005, we had letters of credit outstanding under the Credit Facility totaling $9.5 million, comprised of $4.4 million and $4.3 million for crude oil purchases related to March 2005 and April 2005, respectively and $0.8 million related to other business obligations. The amount that we may have outstanding cumulatively in borrowings and letters of credit under the working capital portion of the facility is subject to a borrowing base calculation. The borrowing base is limited to $50 million -8- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and is calculated monthly. At March 31, 2005, the borrowing base was $42.8 million. Therefore, the remaining amount available for borrowings at March 31, 2005 was $10 million under the working capital portion and $37.5 million under the acquisition portion of the Credit Facility. We have no limitations on making distributions in our Credit Facility, except as to the effects of distributions in covenant calculations. The Credit Facility requires we maintain a cash flow coverage ratio of 1.1 to 1.0. In general, this calculation compares operating cash inflows, as adjusted in accordance with the Credit Facility, less maintenance capital expenditures, to the sum of interest expense and distributions. At March 31, 2005, the calculation resulted in a ratio of 1.3 to 1.0. 5. PARTNERS' CAPITAL AND DISTRIBUTIONS Partners' Capital Partnership equity consists of the general partner interest of 2% and 9,313,811 common units representing limited partner interests of 98%. The general partner interest is held by our General Partner. The Partnership is managed by our general partner. The general partner also holds a 0.01% general partner interest in GCOLP, which is reflected as a minority interest in the consolidated balance sheet at March 31, 2005. Our partnership agreement authorizes our general partner to cause us 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 needs. Distributions Generally, we will distribute 100% of our Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. During 2004, we paid a regular quarterly distribution of $0.15 per unit ($1.4 million in total per quarter). We have declared a $0.15 per unit distribution for the first quarter of 2005, payable on May 13, 2005 to unitholders of record on May 2, 2005. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through March 31, 2005. -9- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net Income Per Common Unit The following table sets forth the computation of basic net income per Common Unit (in thousands, except per unit amounts).
Three Months Ended March 31, ---------------------------- 2005 2004 ----------- ----------- Numerators for basic and diluted net income (loss) per common unit: Income (loss) from continuing operations .................................... $ 2,488 $ (782) Less general partner 2% ownership ........................................... 50 (16) ------- ------- Income (loss) from continuing operations available for common unitholders ... $ 2,438 $ (766) ======= ======= Income (loss) from discontinued operations .................................. $ 282 $ (223) Less general partner 2% ownership ........................................... 6 (4) ------- ------- Income (loss) from discontinued operations available for common unitholders . $ 276 $ (219) ======= ======= Denominator for basic and diluted per Common Unit - weighted average number of Common Units outstanding ............................................. 9,314 9,314 ======= ======= Basic and diluted net income (loss) per Common Unit: Income (loss) from continuing operations .................................... $ 0.26 $ (0.09) Income (loss) from discontinued operations .................................. 0.03 (0.02) ------- ------- Net income (loss) ........................................................... $ 0.29 $ (0.11) ======= =======
6. BUSINESS SEGMENT INFORMATION Our operations consist of three operating segments: (1) Crude Oil Gathering and Marketing - the purchase and sale of crude oil at various points along the distribution chain; (2) Pipeline Transportation - interstate and intrastate crude oil, natural gas and CO2 pipeline transportation; and (3) CO2 marketing - the sale of CO2 acquired under a volumetric production payment to industrial customers. We evaluate segment performance based on segment margin before depreciation and amortization. All of our revenues are derived from, and all of our assets are located in, the United States. -10- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil Gathering and Pipeline CO2 Marketing Transportation Marketing Total -------------- -------------- --------- --------- (in thousands) Three Months Ended March 31, 2005 Revenues: External Customers.......................................... $ 247,008 $ 6,633 $ 2,280 $ 255,921 Intersegment (a)............................................ - 679 - 679 -------------- ------------ -------- --------- Total revenues of reportable segments....................... $ 247,008 $ 7,312 $ 2,280 $ 256,600 ============== ============ ======== ========= Segment margin excluding depreciation and amortization (b).. $ 888 2,443 $ 1,525 $ 4,856 Capital expenditures........................................ $ 22 $ 3,676 $ - $ 3,698 Maintenance capital expenditures............................ $ 22 $ 489 $ - $ 511 Net fixed and other long-term assets (c).................... $ 6,096 $ 35,591 $ 25,708 $ 67,395 Three Months Ended March 31, 2004 Revenues: External Customers.......................................... $ 192,996 $ 3,263 $ 1,831 $ 198,090 Intersegment (a)............................................ - 822 - 822 -------------- ------------ -------- --------- Total revenues of reportable segments....................... $ 192,996 $ 4,085 $ 1,831 $ 198,912 ============== ============ ======== ========= Segment margin excluding depreciation and amortization (b).. $ 1,006 1,853 $ 1,240 $ 4,099 Capital expenditures........................................ $ 51 $ 349 $ - $ 400 Maintenance capital expenditures............................ $ 51 $ 104 $ - $ 155 Net fixed and other long-term assets (c).................... $ 5,211 $ 28,903 $ 23,550 $ 57,664
a) Intersegment sales were conducted on an arm's length basis. b) Segment margin was calculated as revenues less cost of sales and operations expense. A reconciliation of segment margin to operating (loss) income from continuing operations for the periods presented is as follows:
Three Months Ended March 31, ---------------------------- 2005 2004 ----------- ----------- (in thousands) Segment margin excluding depreciation and amortization.. $ 4,856 $ 4,099 General and administrative expenses..................... (858) (3,164) Depreciation, amortization and impairment............... (1,526) (1,547) Net gain on disposal of surplus assets.................. 371 - ---------- ---------- Operating income (loss) from continuing operations...... $ 2,843 $ (612) ========== ==========
c) Net fixed and other long-term assets are the measure used by management in evaluating the results of its operations on a segment basis. Current assets are not allocated to segments as the amounts are shared by the segments or are not meaningful in evaluating the success of the segment's operations. -11- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. 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 then-existing market conditions. Sales and Purchases of Crude Oil Purchases of crude oil from Denbury for the three months ended March 31, 2005 and 2004 were $0.5 million and $23.0 million, respectively. Denbury began shipping its own crude oil on our Mississippi System in September 2004, so our purchases of crude oil from Denbury (and our related crude oil sales) have declined. Transportation Services In September 2004, we entered into an agreement with Denbury where we would provide truck transportation services to Denbury to move its crude oil from the wellhead to our Mississippi pipeline. Previously we had purchased Denbury's crude oil and trucked the oil for our account. Denbury pays us a fee for this trucking service that varies with the distance the crude oil is trucked. For the three months ended March 31, 2005, we received fees from Denbury totaling $0.2 million. These fees are reflected in the statement of operations as gathering and marketing revenues. In September 2004, Denbury also became a shipper on our Mississippi pipeline. Fees for this transportation service totaled $0.9 million for the three months ended March 31, 2005. We also billed Denbury $0.3 million under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven CO2 pipeline and recorded $0.2 million of pipeline transportation income from these arrangements. See Note 3. We also provide pipeline monitoring services to Denbury for which we charged $7,000 and $4,000 for the three months ended March 31, 2005 and 2004, respectively. This revenue is included in pipeline revenues in the statement of operations. General and Administrative Services We do not directly employ any persons to manage or operate our business. Those functions are provided by the General Partner. We reimburse the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by us were $4.1 million and $3.4 million for the three months ended March 31, 2005 and 2004, respectively. Due to and from Related Parties At March 31, 2005 and December 31, 2004, we owed Denbury $0.1 million and $0.7 million, respectively, for purchases of crude oil. Additionally, we owed Denbury $0.5 million and $0.5 million for CO2 transportation services at March 31, 2005 and December 31, 2004, respectively. Denbury owed us $0.5 million and $0.4 million for transportation services at March 31, 2005 and December 31, 2004, respectively. We had advanced $0.6 million and $0.1 million to the General Partner at March 31, 2005 and December 31, 2004, respectively, for administrative services. Directors' Fees In both the first quarter of 2005 and 2004, we paid $30,000 to Denbury for the services of each of four of Denbury's officers who serve as directors of our general partner, the same rate at which our independent directors were paid. CO2 Volumetric Production Payment and Transportation We acquired volumetric production payments from Denbury in 2005 and 2004. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2 for us to our customers. For the three months ended March 31, 2005 and 2004, we paid Denbury $0.7 million and $0.6 million for these transportation services related to our sales of CO2. -12- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Financing Our general partner, a wholly owned subsidiary of Denbury, guarantees our obligations under the Credit Facility. Our general partner's principal assets are its general and limited partnership interests in us. The obligations are not guaranteed by Denbury or any of its other subsidiaries. 8. MAJOR CUSTOMERS AND CREDIT RISK We derive our revenues from customers primarily in the crude oil industry. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of major international corporate entities with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. Occidental Energy Marketing, Inc., Plains All American, L.P. and Shell Oil Company accounted for 28%, 11% and 10% of total revenues for the first quarter of 2005, respectively. ExxonMobil Corporation, Marathon Ashland Petroleum LLC and Plains All American, L.P. accounted for 15%, 14% and 10% of total revenues during the first quarter of 2004, respectively. The majority of the revenues from these customers in both periods relate to our gathering and marketing operations. 9. SUPPLEMENTAL CASH FLOW INFORMATION We received interest payments of $6,000 and $24,000 for the three months ended March 31, 2005 and 2004, respectively. Payments of interest and commitment fees were $14,000 and $52,000 for the three months ended March 31, 2005 and 2004, respectively. At March 31, 2005, we had incurred liabilities for fixed asset additions totaling $0.1 million that had not been paid at the end of the quarter, and, therefore, are not included in the caption "Additions to property and equipment" on the Consolidated Statements of Cash Flows. 10. DERIVATIVES Our market risk in the purchase and sale of crude oil contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps. Historically, any contracts we have used to hedge market risk were less than one year in duration. We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil prices. Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We mark to fair value our derivative instruments at each period end with changes in fair value of derivatives not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. Unrealized gains or losses on derivative transactions qualifying as cash flow hedges are reflected in other comprehensive income. -13- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We regularly review our contracts to determine if the contracts qualify for treatment as derivatives. At March 31, 2005, we had futures contracts on the NYMEX qualifying as derivatives that did not meet the criteria for hedge accounting. The fair value of these contracts was determined based on the closing price for such contracts on the NYMEX on March 31, 2005. We marked these contracts to fair value at March 31, 2005, and recorded a loss of $9,000 which is included in the consolidated statement of operations under the caption "Crude Oil Costs". We determined that the remainder of our derivative contracts qualified for the normal purchase and sale exemption and were designated as such at March 31, 2005 and December 31, 2004. 11. CONTINGENCIES Guarantees We have guaranteed $3.6 million of residual value related to the leases of tractors and trailers from Ryder Transportation, Inc. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote. Along with our general partner, we have guaranteed the payments by GCOLP to the banks under the terms of the Credit Facility related to borrowings and letters of credit. Borrowings at March 31, 2005 were $17.5 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. In general, we expect to incur expenditures in the future to comply with increasing levels of regulatory safety standards. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will expend a total of approximately $2.0 million during 2005 and 2006 for testing and improvements under regulations requiring assessment of the integrity of crude oil pipelines. Pennzoil Litigation We were named a defendant in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176. From Genesis, Pennzoil-Quaker State Company (PQS) was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurance carriers settled this litigation for $12.8 million. PQS is also a defendant in five consolidated class action/mass tort actions 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 a third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter. We currently have no reason to believe that this matter would have a material financial effect on our financial position, results of operations, or cash flows. Environmental In 1992, Howell Crude Oil Company (Howell) entered into a sublease with Koch Industries, Inc., of land located in Santa Rosa County, Florida to operate a crude oil trucking station, known as Jay Station. The sublease provided that Howell would indemnify Koch for environmental contamination on the property under certain circumstances. Howell operated the Jay Station from 1992 until December of 1996 when this operation was sold to us by Howell. We operated Jay Station as a crude oil trucking station until 2003. Koch has indicated that they may make a claim against us under the indemnification provisions of the sublease for environmental contamination on the site and surrounding areas. Genesis and Howell, now a subsidiary of Anadarko Petroleum Corporation, are investigating whether Genesis and/or Howell may have liability for this contamination, and if so, to what extent. Based upon the early stage of this investigation, and subject to resolution of the allocation of responsibility between us and Howell and the -14- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS method and timing of any required remediation, we currently have no reason to believe that this matter would have a material financial effect on our financial position, results of operations, or cash flows. We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may not substantially affect our business. Other Matters We have taken additional security measures since the terrorist attacks of September 11, 2001 in accordance with guidance provided by the Department of Transportation and other government agencies. We cannot assure you that these security measures would prevent our facilities from a concentrated attack. Any future attacks on us or our customers or competitors could have a material effect on our business, whether insured or not. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Such matters presently pending are not expected to have a material adverse effect on our financial position, results of operations or cash flows. 12. SUBSEQUENT EVENT Syngas Investment On April 1, 2005 we acquired a 50% partnership interest in T & P Syngas Supply Company (T&P Syngas) for $13.5 million from TCHI Inc., a wholly owned subsidiary of ChevronTexaco Global Energy Inc. Hydrogen Supply, Inc. ("Praxair") holds the other 50% interest in T&P Syngas. The acquisition was financed through our Credit Facility. T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas. The facility processes natural gas to produce syngas (a combination of carbon monoxide and hydrogen) and high pressure steam. Praxair provides the raw materials to be processed and T&P Syngas receives a fee from Praxair for the processing. T&P Syngas is managed by a management committee consisting of two representatives each from Praxair and us. The T&P Syngas management committee has an approved resolution that provides that cash distributions will be paid quarterly to the partners of the amount of cash on hand in excess of $100,000. Distribution On April 21, 2005, the Board of Directors of the General Partner declared a cash distribution of $0.15 per Unit for the quarter ended March 31, 2005. This distribution will be paid on May 13, 2005 to our general partner and all common unitholders of record as of the close of business on May 2, 2005. -15- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Included in Management's Discussion and Analysis are the following sections: - Overview - Acquisitions in 2005 - Results of Operations and Outlook for 2005 and Beyond - Liquidity and Capital Resources - Commitments and Off-Balance Sheet Arrangements - Other Matters - New Accounting Pronouncements In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and Available Cash before Reserves. Our profitability depends to a significant extent upon our ability to maximize segment margin. Segment margin is calculated as revenues less cost of sales and operating expense, and does not include depreciation and amortization. A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 6 to the consolidated financial statements. Available Cash before Reserves is a non-GAAP measure calculated as net income with several adjustments, the most significant of which are the elimination of gains and losses on asset sales, except those from the sale of surplus assets, the addition of non-cash expenses such as depreciation, and the subtraction of maintenance capital expenditures, which are expenditures to sustain existing cash flows but not to provide new sources of revenues. For additional information on Available Cash before Reserves and a reconciliation of this measure to cash flows from operations, see "Liquidity and Capital Resources - - Non-GAAP Financial Measure" below. OVERVIEW We operate in three business segments - crude oil gathering and marketing, pipeline transportation and CO2 marketing. We generate revenues by selling crude oil and CO2 and by charging fees for the transportation of crude oil, natural gas and CO2 on our pipelines. Our focus is on the margin we earn on these revenues, which is calculated by subtracting the costs of the crude oil, the costs of transporting the crude oil, natural gas and CO2 to the customer, and the costs of operating our assets. Our primary goal is to generate Available Cash before Reserves for our unitholders. This Available Cash before Reserves is then distributed quarterly to our unitholders. During the first quarter of 2005, we generated Available Cash before Reserves that enabled us to pay our regularly quarterly distribution and build reserves toward any future distribution shortfalls. We generated net income for the first quarter of 2005 from a combination of three main sources. These sources included the results of our operating activities, the sale of idle assets, and the effects of decreasing the liability under our incentive compensation plan. Our gathering and marketing segment performed better than it did in the fourth quarter of 2004, but not as well as it did in the first quarter of 2004. Higher field costs due to increased fuel prices and increases in payroll and fleet repair costs were the primary factors for the reduction in our segment margin. Our pipeline transportation segment showed improvement in the first quarter of 2005 as compared to the prior year first quarter. The sale of crude oil volumes deducted from shippers as pipeline loss allowances that exceeded actual losses at high crude oil prices in 2005 contributed to this increase in segment margin. We sold idle assets during the first quarter of 2005, realizing a gain of $0.7 on the sales. These idle assets included a segment of our Mississippi pipeline that had been out of service since 2002, and two segments of our Texas pipeline that we no longer used due to the sale of part of that system to TEPPCO in 2003. We have a stock appreciation rights plan under which employees and directors are granted rights to receive cash upon exercise for the difference between the strike price of the rights and the market price for our units at the time of -16- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS exercise. These rights vest over several years. As of March 31, 2005, the outstanding rights had no value as our unit price was below the strike price of the rights. As our unit price declined from $12.60 at December 31, 2004 to $8.90 per unit at March 31, 2005, we decreased our liability during the first quarter from $1.3 million to zero, recording a credit of $1.3 million. ACQUISITIONS IN 2005 GAS GATHERING AND MARKETING ASSETS In January 2005, we acquired fourteen natural gas pipeline and gathering systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset Group, L.P. for $3.1 million. These fourteen systems are comprised of 60 miles of pipeline and related assets. This acquisition was financed through our credit agreement. The results of this acquisition are included in our pipeline transportation segment. SYNGAS INVESTMENT On April 1, 2005 we acquired a 50% interest in T&P Syngas Supply Company (T&P Syngas) for $13.5 million. We made this acquisition from TCHI Inc., a wholly owned subsidiary of ChevronTexaco Global Energy Inc. Praxair Hydrogen Supply, Inc. ("Praxair") holds the other 50% interest in the partnership. T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas. This facility processes natural gas to produce syngas (a combination of carbon monoxide and hydrogen) and high pressure steam. Praxair provides the raw materials to be processed and receives the syngas and steam produced by the facility under a long-term processing agreement. T&P Syngas receives a processing fee for its services. T&P Syngas is managed by a management committee consisting of two representatives each from Praxair and us. The T&P Syngas management committee has an approved resolution that provides that cash distributions will be paid quarterly to the partners of the amount of cash on hand in excess of $100,000. The acquisition was financed through our credit agreement. RESULTS OF OPERATIONS AND OUTLOOK FOR THE REMAINDER OF 2005 AND BEYOND CRUDE OIL GATHERING AND MARKETING OPERATIONS The key factors affecting our crude oil gathering and marketing segment margin include production volumes, volatility of P-Plus, volatility of grade differentials, inventory management, field operating costs and credit costs. These factors are discussed in detail in our Annual Report on Form 10-K for the year ended December 31, 2004. Segment margins from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels for crude oil do not necessarily bear a relationship to segment margin as absolute price levels normally impact revenues and costs of sales by equivalent amounts. Because period-to-period variations in revenues and costs of sales are not generally meaningful in analyzing the variation in segment margin for gathering and marketing operations, these changes are not addressed in the following discussion. Field operating costs primarily consist of the costs to operate our fleet of 53 trucks (51 leased and 2 owned) used to transport crude oil, and the costs to maintain the trucks and assets used in the crude oil gathering operation. Approximately 54% of these costs are variable and increase or decrease with volumetric changes. These costs include payroll and benefits (as drivers are paid on a commission basis based on volumes), maintenance costs for the trucks (as we lease the trucks under full service maintenance contracts under which we pay a maintenance fee per mile driven), and fuel costs. Fuel costs also fluctuate based on changes in the market price of diesel fuel. Fixed costs include the base lease payment for the vehicle, insurance costs and costs for environmental and safety related operations. - 17- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Operating results from continuing operations for our crude oil gathering and marketing segment were as follows:
Three Months Ended March 31, 2005 2004 ----------- ------------ (in thousands) Revenues.................................. $ 247,008 $ 192,996 Crude oil costs........................... (242,279) (188,947) Field operating costs..................... (3,832) (3,043) Change in fair value of derivatives....... (9) - ----------- ------------ Segment margin......................... $ 888 $ 1,006 =========== ============ Volumes per day: Crude oil wellhead - barrels........... 41,969 48,445 Crude oil total - barrels.............. 58,346 60,591 Crude oil transported only - barrels... 5,122 262
Three Months Ended March 31, 2005 as Compared to Three Months Ended March 31, 2004 Gathering and marketing segment margins decreased $0.1 million or 12% to $0.9 million for the three months ended March 31, 2005, as compared to $1.0 million for the three months ended March 31, 2004. The primary reason for this decrease in segment margin was an increase in field costs of $0.8 million. The majority of the increase over the 2004 first quarter related to higher fuel costs and higher personnel costs. Fuel costs have increased over $0.60 per gallon since the 2004 quarter. We also had five additional tractor/trailers in the 2005 quarter than in 2004, increasing our fixed lease payments. Due to competition for wellhead barrels in the areas in which we operate, we were not able to adjust the purchase price of the crude oil for these cost increases. Partially offsetting the effects of the increased field costs were three primary factors as follows: - A $0.4 million increase in revenues from volumes that we transported for a fee but did not purchase. Approximately one-half of this revenue related to volumes transported for Denbury. In the 2004 period, we purchased Denbury's crude oil at the wellhead, incurring all risk of loss and price variations. Beginning in September 2004, Denbury started selling its production to the end-market directly, and we only provide transportation services for fees in our trucks and in our pipeline. - A $0.2 million increase in the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and - A $0.1 million decrease in credit costs related to crude oil transactions. Outlook for 2005 and Beyond Based on past experience and knowledge of the crude oil gathering and marketing segment, we continue to expect volatility from this segment. We continue to take steps to improve the performance of this segment. These steps include effectively managing relationships with suppliers; inventory management; controlling field costs; and improving operational efficiency in the field. PIPELINE TRANSPORTATION OPERATIONS We operate three crude oil common carrier pipeline systems in a four state area. We refer to these pipelines as our Texas System, Mississippi System and Jay System. Volumes shipped on these systems for the first quarters of 2005 and 2004 are as follows: - 18- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31, ------------------ Pipeline System - barrels per day 2005 2004 - --------------------------------- ------ ------ Texas 29,828 42,206 Mississippi 16,139 10,495 Jay 14,853 15,882
Volumes on our Texas System averaged 29,828 barrels per day during the first quarter of 2005. The crude oil that enters our system comes to us at West Columbia where we have a connection to TEPPCO's South Texas System and at Webster where we have connections to two other pipelines. One of these connections at Webster is with ExxonMobil Pipeline and is used to receive volumes that originate from TEPPCO's pipelines. Under the terms of our 2003 sale of portions of the Texas System to TEPPCO, we had a joint tariff with TEPPCO through October 2004 under which we earned $0.40 per barrel on the majority of the barrels we deliver to the shipper's facilities. This tariff declined to $0.20 per barrel in November 2004. Most of the volume being shipped on our Texas System goes to two refineries on the Texas Gulf Coast. The Mississippi System begins in Soso, Mississippi and extends to Liberty, Mississippi. At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest. The system has been improved to handle the increased volumes produced by Denbury and transported on the pipeline. In order to handle expected future increases in production volumes in the area, we have made capital expenditures for tank, station and pipeline improvements, and we intend to make further improvements. See Capital Expenditures under "Liquidity and Capital Resources" below. Beginning in September 2004, Denbury became a shipper on the Mississippi System under an incentive tariff designed to encourage shippers to increase volumes shipped on the pipeline. Prior to this point, Denbury sold its production to us before it entered the pipeline. In the fourth quarter of 2004, we constructed two segments of crude oil pipeline to connect producing fields operated by Denbury to our Mississippi System. One of these segments was placed in service in 2004 and the other began operation in the first quarter of 2005. Denbury pays us a minimum payment each month for the right to use these pipeline segments. We account for these arrangements as direct financing leases. The Jay pipeline system in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Although volumes on this pipeline had been declining steadily in recent years due to declining production in the surrounding area, new production in the area has reduced the impact of those declines. Historically, the largest operating costs in our crude oil pipeline segment have consisted of personnel costs, power costs, maintenance costs and costs of compliance with regulations. Some of these costs are not predictable, such as failures of equipment, or are not within our control, like power cost increases. We perform regular maintenance on our assets to keep them in good operational condition and to minimize cost increases. In the fourth quarter of 2004, we constructed a CO2 pipeline in Mississippi to transport CO2 from Denbury's main CO2 pipeline to an oil field from which we also constructed an oil pipeline to bring the oil from the field to our existing Mississippi pipeline. Denbury has the exclusive right to use this CO2 pipeline. This arrangement has been accounted for as a direct financing lease. Operating results from continuing operations for our pipeline transportation segment were as follows: - 19- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31, 2005 2004 ----------- ------------ (in thousands) Revenues from tariffs, including revenues from direct financing leases........................ $ 4,623 $ 4,085 Revenues from natural gas sales................... 2,689 - Natural gas purchases............................. (2,636) - Pipeline operating costs.......................... (2,233) (2,232) ----------- ------------ Segment margin................................. $ 2,443 $ 1,853 =========== ============ Volumes per day from continuing operations: Crude oil pipeline - barrels................... 60,821 68,583
Three Months Ended March 31, 2005 Compared with Three Months Ended March 31, 2004 Pipeline segment margin increased $0.6 million or 32% to $2.4 million for the three months ended March 31, 2005, as compared to $1.9 million for the three months ended March 31, 2004. The increase in pipeline segment margin is primarily attributable to an increase in pipeline revenues from tariffs and related services. A breakdown of these revenues in each period is as follows:
Three Months Ended March 31, 2005 2004 ----------- ------------ (in thousands) Crude oil tariffs and revenues from direct financing lease of crude oil pipelines...................... $ 3,263 $ 3,297 Sales of crude oil pipeline loss allowance volumes............. 1,079 787 Revenues from direct financing leases of CO2 pipelines......... 92 - Natural gas tariffs............................................ 56 - Tank rental reimbursements and other miscellaneous revenues.... 133 1 ----------- ------------ Revenues from tariffs....................................... $ 4,623 $ 4,085 =========== ============
The effects of declines in volumes shipped on the Texas System and the lower tariff on that system were offset by increased volumes and higher tariffs on the Mississippi System. Revenues from sales of crude oil volumes deducted from shippers as pipeline loss allowances that exceeded actual losses increased in the 2005 first quarter as a result of higher crude oil market prices. The CO2 pipeline did not exist in the first quarter of 2004, and the natural gas gathering pipelines were acquired in the first quarter of 2005. Under a tank rental reimbursement arrangement with the largest shipper on the Texas System that began in January 2005, we receive reimbursement for the costs of renting tankage at Webster. In some cases we only transport natural gas for producers on our natural gas gathering pipelines. We recorded natural gas tariffs for these services totaling $56,000 in the first quarter of 2005. In other cases, we acquire the natural gas that we gather utilizing our natural gas gathering pipelines, recording gas sales and purchases. The net profit from the sale of this gas added an additional $53,000 to the pipeline transportation segment. Costs of operating the pipelines remained the same as in the 2004 period. Outlook for 2005 and Beyond We anticipate that volumes on the Texas System may continue to decline as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's pipeline systems. - 20- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The tank rental reimbursement arrangement with the largest shipper on the Texas System is expected to increase revenues from the Texas System by $0.5 million annually, offsetting a portion of the expected decrease in tariff revenues. We completed a hydrotest in the first quarter of 2005 that we believe will allow us to continue to operate the West Columbia to Webster segment of pipeline for service in heavy oil. This oil will be shipped under a joint tariff with TEPPCO. The shippers agreed to an increase in this tariff during the fourth quarter of 2004 if we would continue to provide this service which will provide us with additional return on our investment in this segment. We expect an annual increase in tariff revenues of $0.6 million, based on volumes shipped in the fourth quarter of 2004. Denbury is the largest oil and gas producer in Mississippi. Our Mississippi System is adjacent to several of Denbury's existing and prospective oil fields. There are mutual benefits to Denbury and us due to this common production and transportation area. As Denbury continues to acquire and develop old oil fields using CO2 based tertiary recovery operations, Denbury expects to add crude oil gathering and CO2 supply infrastructure to these fields. Further, as the fields are developed over time, it may create increased demand for our crude oil transportation services. Beginning in September 2004, Denbury began shipping on our Mississippi System rather than selling the crude oil to us to market and ship on our Mississippi System. We also restructured our tariffs to provide additional return on the investments we have made and will continue to make in the Mississippi System. We built a CO2 pipeline to connect Denbury's existing CO2 pipeline to the Brookhaven oil field in Mississippi. The agreement with Denbury provides for a minimum capacity charge that will provide $0.6 million of annual payments to us for eight years with a commodity charge for volumes in excess of a threshold volume. The segments of crude oil pipeline we constructed to Denbury's Olive and Brookhaven fields also have agreements providing for minimum capacity charges for ten years with commodity charges for volumes in excess of threshold volumes. The payments under these crude oil transportation agreements will provide a combined total of $0.6 million of annual payments to us, in addition to the amount received for the CO2 pipeline. The Brookhaven CO2 and Olive pipelines went into service in 2004 and the Brookhaven oil pipeline began service in the first quarter of 2005. We account for these arrangements as direct financing leases. We believe that the best use of the Jay System may be to convert it to natural gas service. We continue to review opportunities to effect such a conversion. Part of the process will involve finding alternative methods for us to continue to provide crude oil transportation services in the area. While we believe this initiative has long-term potential, it is not expected to have a substantial impact on us during 2005 or 2006. We will continue to evaluate opportunities to dispose of or to make further investments in components of this segment in order to improve its performance. CARBON DIOXIDE (CO2) OPERATIONS In November 2003, we acquired a volumetric production payment ("VPP") of 167.5 Bcf of CO2 from Denbury and in September 2004 we acquired an additional 33.0 Bcf VPP. Denbury owns 2.7 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the production payments, Denbury also assigned to us five of their existing long-term CO2 contracts with industrial customers. Denbury owns the pipeline that is used to transport the CO2 to our customers as well as to its own tertiary recovery operations. The volumetric production payments entitle us to a maximum daily quantity of CO2 of 65,250 thousand cubic feet (Mcf) per day through December 31, 2009, 55,750 Mcf per day for the calendar years 2010 through 2012, and 37,750 Mcf per day beginning in 2013 until we have received all volumes under the production payments. Under the terms of transportation agreements with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee from us of $0.16 per Mcf, subject to adjustments for inflation, for those transportation services. The industrial customers treat the CO2 and transport it to their own customers. The primary industrial applications of CO2 by these customers include beverage carbonation and food chilling and freezing. Based on - 21- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Denbury's and our experience in 2003 and 2004, we can expect some seasonality in our sales of CO2. The dominant months for beverage carbonation and freezing food are from April to October, when warm weather increases demand for beverages and the approaching holidays increase demand for frozen foods. The average daily sales (in mcfs) of CO2 for each quarter in 2005, 2004 and 2003 under these contracts were as follows:
Quarter 2005 2004 2003 - ------- ------ ------ ------ First 47,808 45,671 45,038 Second 51,164 49,982 Third 53,095 50,679 Fourth 48,217 42,468
The terms of our contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The maximum daily contract quantity per year in the contracts totals 61,500 Mcf. Under the minimum take-or-pay volumes, the customers must purchase a total of 31,292 Mcf per day whether received or not. Any volume purchased under the take-or-pay provision in any year can then be recovered in a future year as long as the minimum requirement is met in that year. In the two years ended December 31, 2004, all three customers purchased more than their minimum take-or-pay quantities, as shown in the table above. Our five industrial contracts expire at various dates beginning in 2010 and extending through 2016. The sales contracts contain provisions for adjustments for inflation to sales prices based on the Producer Price Index, with a minimum price. Operating results from continuing operations for our CO2 marketing segment were as follows:
Three Months Ended March 31, 2005 2004 ----------- ------------ (in thousands) Revenues................. $ 2,280 $ 1,831 Marketing costs.......... (755) (591) ----------- ------------ Segment margin........ $ 1,525 $ 1,240 =========== ============ Volumes per day: CO2 marketing - Mcf... 47,808 45,671
Three Months Ended March 31, 2005 Compared with Three Months Ended March 31, 2004 Revenues, costs and segment margin have increased due to the higher volumes sold during the 2005 first quarter. The average segment margin per Mcf of CO2 sold was $0.35 in the first quarter of 2005 as compared to $0.30 for the first quarter of 2004. Because of differing contractual arrangements with the customers, revenues and segment margin are also affected by the specific volumes sold to each customer. DISCONTINUED OPERATIONS In the first quarter of 2005, we sold assets that were no longer in service related to the operations that we sold in 2003, recognizing a gain of $0.3 million. During the first quarter of 2004, we incurred costs totaling $0.2 million related to the dismantlement of assets that we abandoned in 2003. OTHER COSTS AND INTEREST Three Months Ended March 31, 2005 Compared with Three Months Ended March 31, 2004 General and administrative expenses. General and administrative expenses consisted of the following: -22- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31, 2005 2004 ----------- ------------- (in thousands) Expenses excluding the effects of the stock appreciation rights plan....................... $ 2,187 $ 2,060 Stock appreciation rights plan expense (credit)... (1,329) 1,104 ----------- ------------- Total general and administrative expense....... $ 858 $ 3,164 =========== =============
General and administrative expenses decreased by $2.3 million, however, the decrease is attributable entirely to our employee stock appreciation rights plan. This plan is a long-term incentive plan whereby rights are granted for the grantee to receive cash equal to the difference between the grant price and Common Unit price at date of exercise. The rights vest over several years. Our unit price rose 27% from $9.80 at December 31, 2003 to $12.45 at March 31, 2004 resulting in a $1.1 million increase to the accrual for this liability in the first quarter of 2004. In the first quarter of 2005, our unit price declined from $12.60 per unit at December 31, 2004 to $8.90 per unit at March 31, 2005. As a result, all rights are "out of the money", and the liability at December 31, 2004 was reversed. Interest expense, net. In the 2005 first quarter, our net interest expense increased by $0.2 million compared to the 2004 period. In the 2005 period, our average outstanding balance of bank debt was $6.6 million higher than in the 2004 first quarter and our average interest rate was 1.7% greater than in the 2004 period. Gain on disposal of surplus assets. In the 2005 first quarter, we sold the Liberty to Maryland segment of our Mississippi pipeline and two idle segments of pipeline in Texas. The Mississippi segment had been out-of-service since February 2002. The Texas segments were idle as a result of our sale of part of our Texas System to TEPPCO in 2003. Additionally we sold an idle site in Houma, Louisiana. We received $1.3 million from the sales of these assets and realized gains totaling $0.7 million. LIQUIDITY AND CAPITAL RESOURCES CAPITAL RESOURCES At March 31, 2005, we had borrowed $5.0 million under the working capital portion of the Credit Facility and $12.5 million under the acquisition portion. Due to the revolving nature of loans under the Credit Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 1, 2008. At March 31, 2005, we had letters of credit outstanding under the Credit Facility totaling $9.5 million, comprised of $4.4 million and $4.3 million for crude oil purchases related to March 2005 and April 2005, respectively, and $0.8 million related to other business obligations. The amount that we may have outstanding cumulatively in borrowings and letters of credit under the working capital portion of the facility is subject to a borrowing base calculation. The borrowing base is limited to $50 million and is calculated monthly. At March 31, 2005, the borrowing base was $42.8 million. Therefore, the total amount available for borrowings at March 31, 2005 was $10 million under the working capital portion and $37.5 million under the acquisition portion of the Credit Facility. We were in compliance with the Credit Facility covenants at March 31, 2005. We have no limitations on making distributions in our Credit Facility, except as to the effects of distributions in covenant calculations. The Credit Facility requires we maintain a cash flow coverage ratio of 1.1 to 1.0. In general, this calculation compares operating cash inflows, as adjusted in accordance with the Credit Facility, less maintenance capital expenditures, to the sum of interest expense and distributions. At March 31, 2005, the calculation resulted in a ratio of 1.3 to 1.0. The Credit Facility also requires that the level of operating cash inflows, as adjusted in accordance with the Credit Facility, be at least $8.5 million. At March 31, 2005, the result of this calculation was $10.7 million. We will distribute our Available Cash to our Unitholders each quarter if we are not in default of these covenants. -23- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Our average daily outstanding balance under the Credit Facility during the first quarter of 2005 was $10.3 million. The average interest rate we paid during this same period was 7.26%. On April 1, 2005, we borrowed additional funds under the Credit Facility of $13 million to fund the acquisition of T&P Syngas. Market interest rates increased during the first quarter of 2005 by 0.50%, increasing the rate on our borrowings by that same amount during the first quarter. The average interest rate on our outstanding borrowings at March 31, 2005 was 7.5%. CAPITAL EXPENDITURES A summary of our capital expenditures in the three months ended March 31, 2005 and 2004 is as follows:
THREE MONTHS ENDED MARCH 31, ---------------------------- 2005 2004 ----------- ------------ (in thousands) Maintenance capital expenditures: Texas pipeline system....................... $ 14 $ 8 Mississippi pipeline system................. 471 91 Jay pipeline system......................... 5 5 Crude oil gathering assets.................. 9 - Administrative assets....................... 12 51 ----------- ------------ Total maintenance capital expenditures... 511 155 Growth capital expenditures: Mississippi pipeline system................. 79 245 Natural gas gathering assets................ 3,108 - ----------- ------------ Total growth capital expenditures........ 3,187 245 ----------- ------------ Total capital expenditures............ $ 3,698 $ 400 =========== ============
Maintenance capital expenditures in 2005 and 2004 included pipeline and station improvements in Mississippi to handle increased volumes. Administrative assets included computer software and hardware. The growth capital expenditures on the Mississippi system in 2005 included additional tankage. Growth capital expenditures in the first quarter of 2004 related to the acquisition of right-of-way for the extensions of our crude oil pipeline and a CO2 pipeline to Denbury's Brookhaven field. The natural gas gathering assets were acquired from Multifuels in January 2005. Although we have no commitments to make capital expenditures, based on the information available to us at this time, we currently anticipate that our maintenance capital expenditures for 2005 will total to approximately $2.4 million. These expenditures are expected to relate primarily to our Mississippi System, including corrosion control expenditures, minor facility improvements and improvements of the pipeline as a result of integrity management test results. Complying with Department of Transportation Pipeline Integrity Management Program ("IMP") regulations has been and will be a significant factor in determining the amount and timing of our capital expenditure requirements. The IMP regulations required that a baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. We expect to spend $0.1 million in 2005 and $0.2 million in 2006 for pipeline integrity testing that will be charged to pipeline operating expense as incurred. As testing is completed, we are required to take prompt remedial action to address integrity issues raised by the assessment. The rehabilitation action required as a result of the assessment and testing is expected to impact our capital expenditure program by requiring us to make improvements to our pipeline. This creates a difficult budgeting and planning challenge as we cannot predict the results of pipeline testing until they are completed. Based on estimated improvements required from assessments made during 2002 through 2004, we have estimated capital expenditures to be made during the IMP assessment period from 2005 through 2009. These capital expenditure projections are -24- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS based on very preliminary data regarding the cost of rehabilitation. We will update these projections as we obtain additional information. As we rehabilitate the Mississippi System as a result of IMP testing, we will also make improvements to handle increased volumes more efficiently. Overall we expect to spend approximately $2.0 million in 2005 through 2007 for these improvements. We do not expect to incur any rehabilitation expenditures on the other systems during this period. Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and capital discussed below in "Sources of Future Capital." We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows such as the two acquisitions discussed in "Acquisitions in 2005" above. SOURCES OF FUTURE CAPITAL The Credit Facility provides us with $50 million of capacity for acquisitions and $15 million for borrowings under the working capital portion. Both portions of the facility are revolving facilities. At March 31, 2005, we had $17.5 million outstanding under the Credit Facility, and $47.5 million available for borrowings. On April 1, 2005, we borrowed an additional $13.0 million to acquire 50% of T&P Syngas. We expect to use cash flows from operating activities to fund cash distributions and maintenance capital expenditures needed to sustain existing operations. Future acquisitions or capital projects to expand the Partnership will require funding through borrowings under the Credit Facility or from proceeds from equity offerings, or a combination of the two sources of funds. CASH FLOWS Our primary sources of cash flows are operations, credit facilities, and in 2005, proceeds from the sale of idle assets. Our primary uses of cash flows are capital expenditures and distributions. A summary of our cash flows is as follows:
Three Months Ended March 31, ------------------------------ 2005 2004 ----------- ------------- (in thousands) Cash provided by (used in): Operating activities......... $ 2,539 $ (3,603) Investing activities......... $ (2,824) $ (400) Financing activities......... $ 1,338 $ 1,474
Operating. Net cash from operating activities for each period have been comprised of the following:
Three Months Ended March 31, ----------------------------- 2005 2004 ----------- ------------ (in thousands) Net (loss) income............................... $ 2,770 $ (1,005) Depreciation, amortization and impairment....... 1,526 1,640 Gain on sales of assets......................... (653) - Direct financing leases......................... 120 - Other non-cash items............................ (1,227) 1,104 Changes in components of working capital, net... 3 (5,342) ----------- ------------ Net cash from operating activities........... $ 2,539 $ (3,603) =========== ============
Our operating cash flows are affected significantly by changes in items of working capital. In the 2004 period we temporarily funded $6.9 million of a litigation settlement with funds we borrowed and funds on hand. We were reimbursed for this payment by insurers in May 2004, however, at March 31, 2004, we had a net cash outflow related to this payment. Affecting all periods is the timing of capital expenditures and their effects on our recorded liabilities. -25- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 $90.5 million aggregate receivables on our consolidated balance sheet at March 31, 2005, approximately $88.7 million, or 98%, were less than 30 days past the invoice date. Investing. Cash flows used in investing activities in the first quarter of 2005 were $2.8 million as compared to $0.4 million in 2004 period. In 2005, we expended $3.6 million for property additions, including $3.1 million for the natural gas gathering assets acquired from Multifuels. We also made a $0.5 million deposit toward the T&P Syngas acquisition. Offsetting these expenditures was the receipt of $1.3 million for the sale of idle assets. In 2004 we expended $0.2 million for the first phase of an addition to our Mississippi System, by acquiring right-of-ways to be used for a crude oil pipeline and a CO2 pipeline of approximately ten miles. We expended $0.2 million for other capital improvements related to our corporate office and to handling the increased volumes on our Mississippi System more efficiently. Financing. In the first quarters of 2005 and 2004, financing activities provided net cash of $1.3 million and $1.5 million, respectively. We increased our borrowings by $2.2 million, primarily to fund the acquisition of the natural gas assets and to make a deposit for the T&P Syngas interest of $0.5 million. We utilized cash of $1.4 million to make distributions to our partners. In the 2004 first quarter, our outstanding debt increased $2.9 million, primarily related to the funding of a litigation settlement for which we received reimbursement in May 2004. Distributions to our partners were $1.4 million. DISTRIBUTIONS As a master limited partnership, the key consideration of our Unitholders is the amount and reliability of our distribution, and our prospects for distribution increases. We are required by our Partnership Agreement to 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. Beginning with the distribution for the fourth quarter of 2003, which was paid in February 2004, we have paid a quarterly distribution to $0.15 per unit ($1.4 million in total). Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit, and 49% of any distributions in excess of $0.33 per unit, without duplication. We have not paid any incentive distributions. The likelihood and timing of the payment of any incentive distributions will depend on our ability to make accretive acquisitions and generate cash flows from those acquisitions. We do not expect to make incentive distributions during 2005. We believe we will be able to sustain a regular quarterly distribution at $0.15 per unit during 2005. Our ability to increase distributions during 2005 will depend in part on our success in developing and executing capital projects and making accretive acquisitions, the results of our integrity management program testing, and our ability to generate sustained improvements in the gathering and marketing segment. Available Cash before Reserves for the year ended March 31, 2005 is as follows (in thousands): Net income........................................................... $ 2,770 Depreciation and amortization........................................ 1,526 Cash received from direct financing leases not included in income.... 120 Cash effects from sales of certain asset sales....................... 666 Non-cash charges..................................................... (1,370) Maintenance capital expenditures..................................... (511) ----------- Available Cash before Reserves....................................... $ 3,201 ===========
-26- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We have reconciled Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2005 below. NON-GAAP FINANCIAL MEASURE 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 accrual for our stock appreciation rights plan expense and the value of financial instruments; and (3) the subtraction of maintenance capital expenditures. Maintenance capital expenditures are capital expenditures (as defined by GAAP) to replace or enhance partially or fully depreciated assets in order to sustain the existing operating capacity or efficiency of our assets and extend their useful lives. See "Distributions" above. The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the year ended March 31, 2005, is as follows (in thousands):
Three Months Ended March 31, 2005 --------- Cash flows from operating activities................................ $ 2,539 Adjustments to reconcile operating cash flows to Available Cash: Maintenance capital expenditures................................ (511) Proceeds from sales of certain assets........................... 1,319 Amortization of credit facility issuance fees................... (93) Cash effects of stock appreciation rights plan.................. (50) Net effect of changes in operating accounts not included in calculation of Available Cash before Reserves..................................................... (3) --------- Available Cash before Reserves...................................... $ 3,201 =========
COMMITMENTS AND OFF-BALANCE-SHEET ARRANGEMENTS CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS In addition to the Credit Facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes our obligations and commitments at March 31, 2005. -27- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Payments Due by Period --------------------------------------------------- Less than After Contractual Cash Obligations 1 Year 1-3 Years 4-5 Years 5 Years Total - ---------------------------- --------- --------- --------- ------- --------- (in thousands) Long-term Debt................. $ - $ - $ 17,500 $ - $ 17,500 Interest Payments (1).......... 1,281 2,412 202 - 3,895 Operating Leases............... 2,461 2,647 1,465 684 7,257 Unconditional Purchase Obligations (2)............ 196,766 79,861 - - 276,627 --------- --------- --------- ------- --------- Total Contractual Cash Obligations............ $ 200,508 $ 84,920 $ 19,167 $ 684 $ 305,279 ========= ========= ========= ======= =========
(1) Interest on our long-term debt is at market-based rates. Amount shown for interest payments represents interest that would be paid if the debt outstanding at March 31, 2005 remained outstanding through the maturity date of June 1, 2008 and interest rates remained at the March 31, 2005 market levels through June 1, 2008. Actual obligations may differ from the amounts included above. (2) 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 March 31, 2005, were used to value the obligations. Actual obligations may differ from the amounts included above. OFF-BALANCE SHEET ARRANGEMENTS We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under Contractual Obligation and Commercial Commitments above, nor do we have any debt or equity triggers based upon our unit or commodity prices. NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS See discussion of new accounting pronouncements in Note 2 - New Accounting Pronouncements in the accompanying consolidated financial statements. FORWARD LOOKING STATEMENTS The statements in this Quarterly Report on Form 10-Q that are not historical information may be "forward looking statements" within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These statements include, but are not limited to, statements identified by the words "anticipate," "continue," "believe," "estimate," "expect," "plan," "may," "will," or "intend" or the negative of those terms and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. We make these statements based on our experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: - demand for the supply of, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids in the United States, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances; - throughput levels and rates; -28- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - changes in, or challenges to, our tariff rates; - our ability to successfully identify and consummate strategic acquisitions, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations; - service interruptions in our pipeline transportation systems; - shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil or to whom we sell crude oil; - changes in laws or regulations to which we are subject; - our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of existing debt agreements that contain restrictive covenants; - loss of key personnel; - the effects of competition; - our lack of control over the activities and timing and amount of distributions of partnerships in which we have invested that we do not control; - hazards and operating risks that may not be covered fully by insurance; - the condition of the capital markets in the United States; - the political and economic stability of the oil producing nations of the world; and - general economic conditions, including rates of inflation and interest rates. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under "Risk Factors" discussed in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2004. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. -29- ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We may be exposed to market risks primarily related to volatility in crude oil commodity prices and interest rates. Our primary price risk relates to the effect of crude oil price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. We seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. We utilize NYMEX commodity based futures contracts and forward contracts to hedge our exposure to these market price fluctuations as needed. At March 31, 2005, the Partnership had entered into NYMEX future contracts that will settle by July 2005. None of these contracts qualify for hedge accounting, therefore the fair value of theses derivatives have received mark-to-market treatment in current earnings. This accounting treatment is discussed further under Note 2 "Summary of Significant Accounting Policies" of our Consolidated Financial Statements in our Annual Report on Form 10-K. Information about these contracts is contained in the table set forth below:
Sell (Short) Contracts ------------ Futures Contracts: Contract volumes (1,000 bbls)............ 24 Weighted average price per bbl........... $ 55.89 Contract value (in thousands)............ $ 1,332 Mark-to-market change (in thousands)..... 9 ------------ Market settlement value (in thousands)... $ 1,341 ============
The table above presents notional amounts in barrels, the weighted average contract price, total contract amount and total fair value amount in U.S. dollars. Fair values were determined by using the notional amount in barrels multiplied by the March 31, 2005 quoted market prices on the NYMEX. We are also exposed to market risks due to the floating interest rates on our credit facility. Our debt bears interest at the LIBOR or prime rate plus the applicable margin. We do not hedge our interest rates. The average interest rate presented below is based upon rates in effect at March 31, 2005. The carrying value of our debt in our credit facility approximates fair value primarily because interest rates fluctuate with prevailing market rates, and the credit spread on outstanding borrowings reflects market.
Expected Year Of Maturity 2008 (in thousands) -------------- Long-term debt - variable rate 17,500 Average interest rate 7.5%
ITEM 4. CONTROLS AND PROCEDURES We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. As of the end of the period covered by this report, we carried out an evaluation, under the supervision of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are adequate -30- and effective in all material respects in providing to them in a timely manner material information relating to us (including our consolidated subsidiaries) required to be disclosed in this quarterly report. In addition, there have been no significant changes in our internal controls over financial reporting during the three months ended March 31, 2005, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I. Item 1. Note 11 to the Consolidated Financial Statements entitled "Contingencies", which is incorporated herein by reference. ITEM 6. EXHIBITS. (a) Exhibits. Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) 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. 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: May 9, 2005 By: /s/ ROSS A. BENAVIDES ------------------------------ Ross A. Benavides Chief Financial Officer -31- EXHIBIT INDEX Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities SExchange Act of 1934. Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) 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. EX-31.1 2 h25224exv31w1.txt CERTIFICATION OF CEO PURSUANT TO RULE 13A-14(A) Exhibit 31.1 CERTIFICATION I, Mark J. Gorman, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 9, 2005 /s/ Mark J. Gorman ----------------------------------- Mark J. Gorman President & Chief Executive Officer EX-31.2 3 h25224exv31w2.txt CERTIFICATION OF CFO PURSUANT TO RULE 13A-14(A) Exhibit 31.2 CERTIFICATION I, Ross A. Benavides, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 9, 2005 /s/ Ross A. Benavides ------------------------------ Ross A. Benavides Chief Financial Officer EX-32.1 4 h25224exv32w1.txt CERTIFICATION OF CEO PURSUANT TO SECTION 906 Exhibit 32.1 CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the accompanying Quarterly Report of Genesis Energy, L.P. (the "Partnership") on Form 10-Q for the quarter ended March 31, 2005 (the "Report") filed with the Securities and Exchange Commission on the date hereof, I, Mark J. Gorman, President and Chief Executive Officer of Genesis Energy, Inc., the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and (2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. May 9, 2005 /s/ Mark J. Gorman -------------------------------------- Mark J. Gorman President and Chief Executive Officer, Genesis Energy, Inc. EX-32.2 5 h25224exv32w2.txt CERTIFICATION OF CFO PURSUANT TO SECTION 906 Exhibit 32.2 CERTIFICATION BY CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the accompanying Quarterly Report of Genesis Energy, L.P. (the "Partnership") on Form 10-Q for the quarter ended March 31, 2005 (the "Report") filed with the Securities and Exchange Commission on the date hereof, I, Ross A. Benavides, Chief Financial Officer of Genesis Energy, Inc., the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and (2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. May 9, 2005 /s/ Ross A. Benavides ----------------------------- Ross A. Benavides Chief Financial Officer, Genesis Energy, Inc. -----END PRIVACY-ENHANCED MESSAGE-----