10-Q 1 h30139e10vq.txt GENESIS ENERGY, L.P.- SEPTEMBER 30, 2005 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-Q [X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 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 No X ----- ----- Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act.) Yes No X ----- ----- Indicate number of shares of each of the issuer's classes of common stock, as of the latest practicable date. Limited Partner Units outstanding as of November 7, 2005: 9,313,811 ================================================================================ This report contains 36 pages GENESIS ENERGY, L.P. FORM 10-Q INDEX
Page ---- PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Balance Sheets - September 30, 2005 and December 31, 2004.......................................................... 3 Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2005 and 2004...................... 4 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004................................... 5 Consolidated Statement of Partners' Capital for the Nine Months Ended September 30, 2005...................................... 6 Notes to Consolidated Financial Statements....................... 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations......................................... 18 Item 3. Quantitative and Qualitative Disclosures about Market Risk....... 35 Item 4. Controls and Procedures.......................................... 35 PART II. OTHER INFORMATION Item 1. Legal Proceedings................................................ 36 Item 6. Exhibits and Reports on Form 8-K................................. 36 SIGNATURES .............................................................. 36
-2- GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands) (Unaudited)
September 30, December 31, 2005 2004 ------------- ------------ ASSETS CURRENT ASSETS Cash and cash equivalents ................................ $ 2,149 $ 2,078 Accounts receivable: Trade ................................................. 94,898 68,737 Related party ......................................... 522 584 Inventories .............................................. 4,825 1,866 Net investment in direct financing leases, net of unearned income - current portion ..................... 522 318 Insurance receivable ..................................... 2,041 2,125 Other .................................................... 2,499 1,688 -------- -------- Total current assets .................................. 107,456 77,396 FIXED ASSETS, at cost ....................................... 69,192 73,023 Less: Accumulated depreciation ........................... (35,128) (39,237) -------- -------- Net fixed assets ...................................... 34,064 33,786 NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income ................................................... 6,077 4,247 CO2 ASSETS, net of amortization ............................. 24,327 26,344 INVESTMENT IN T&P SYNGAS SUPPLY COMPANY ..................... 13,365 -- OTHER ASSETS, net of amortization ........................... 1,330 1,381 -------- -------- TOTAL ASSETS ................................................ $186,619 $143,154 ======== ======== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable: Trade ................................................. $ 99,289 $ 74,176 Related party ......................................... 2,253 1,239 Accrued liabilities ...................................... 7,895 6,523 -------- -------- Total current liabilities ............................. 109,437 81,938 LONG-TERM DEBT .............................................. 32,600 15,300 OTHER LONG-TERM LIABILITIES ................................. 186 160 COMMITMENTS AND CONTINGENCIES (Note 12) MINORITY INTERESTS .......................................... 517 517 PARTNERS' CAPITAL Common unitholders, 9,314 units issued and outstanding ... 42,994 44,326 General partner .......................................... 885 913 -------- -------- Total partners' capital ............................... 43,879 45,239 -------- -------- TOTAL LIABILITIES AND PARTNERS' CAPITAL ..................... $186,619 $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 September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2005 2004 2005 2004 -------- -------- -------- -------- REVENUES: Crude oil gathering and marketing: Unrelated parties (including revenues from buy/sell arrangements in the three and nine months of 2005 of $102,893 and $279,285 and $78,876 and $210,311 in the three and nine months of 2004) ................. $290,887 $244,377 $785,161 $663,245 Related parties .......................................... 187 -- 613 -- Pipeline transportation, including natural gas sales: Unrelated parties ........................................ 5,849 3,787 17,776 11,958 Related parties .......................................... 1,131 277 3,400 277 CO2 revenues ................................................ 2,523 2,295 7,371 6,275 -------- -------- -------- -------- Total revenues ........................................... 300,577 250,736 814,321 681,755 COSTS AND EXPENSES: Crude oil costs: Unrelated parties (including crude oil costs from buy/sell arrangements in the three and nine months of 2005 of $102,304 and $278,703 and $78,511 and $209,499 in the three and nine months of 2004) ........ 284,518 214,864 767,864 573,145 Related parties .......................................... 1,421 25,092 3,422 76,491 Field operating .......................................... 4,082 3,473 12,097 9,711 Pipeline transportation costs: Pipeline operating costs ................................. 2,917 1,463 7,450 6,124 Natural gas purchases .................................... 2,178 -- 6,590 -- CO2 distribution costs: Transportation costs - related party ..................... 806 726 2,296 1,954 Other costs .............................................. 37 26 113 77 General and administrative .................................. 3,210 2,639 6,536 7,825 Depreciation and amortization ............................... 1,601 2,599 4,695 5,773 Net (gain) loss on disposal of surplus assets ............... (84) 10 (482) (65) -------- -------- -------- -------- OPERATING (LOSS) INCOME ..................................... (109) (156) 3,740 720 OTHER INCOME (EXPENSE): Equity in earnings of investment in T&P Syngas .............. 8 -- 260 -- Interest income ............................................. 10 9 38 37 Interest expense ............................................ (550) (212) (1,439) (738) -------- -------- -------- -------- (LOSS) Income from continuing operations .................... (641) (359) 2,599 19 Income (loss) from operations of discontinued Texas System .. 45 (35) 318 (319) -------- -------- -------- -------- NET (LOSS) INCOME ........................................... $ (596) $ (394) $ 2,917 $ (300) NET (LOSS) INCOME PER COMMON UNIT - BASIC AND DILUTED: (Loss) income from continuing operations ................ $ (0.06) $ (0.04) $ 0.28 $ 0.00 (Loss) income from discontinued operations .............. 0.00 0.00 0.03 (0.03) -------- -------- -------- -------- NET (LOSS) INCOME ........................................... $ (0.06) $ (0.04) $ 0.31 $ (0.03) WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING ......... 9,314 9,314 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)
Nine Months Ended September 30, ------------------------------- 2005 2004 -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 2,917 $ (300) Adjustments to reconcile net income to net cash provided by operating activities - Depreciation ..................................................................... 2,678 3,976 Amortization of CO2 contracts .................................................... 2,017 1,797 Amortization of credit facility issuance costs ................................... 279 289 Amortization of unearned income on direct financing leases ....................... (521) -- Payments received under direct financing leases .................................. 890 -- Equity in earnings of investment in T&P Syngas ................................... (260) -- Distributions from T&P Syngas that are a return on investment .................... 260 -- Change in fair value of derivatives .............................................. (1,101) (16) Gain on asset disposals .......................................................... (800) (65) Other non-cash charges ........................................................... 23 564 Changes in components of working capital - Accounts receivable ........................................................... (26,099) (8,905) Inventories ................................................................... (3,537) (1,679) Other current assets .......................................................... (727) 13,756 Accounts payable .............................................................. 25,860 10,338 Accrued liabilities ........................................................... 2,364 (15,476) -------- -------- Net cash provided by operating activities .............................................. 4,243 4,279 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment ................................................. (5,374) (4,493) Investment in T&P Syngas Supply Company ............................................. (13,418) -- Distributions from T&P Syngas that are a return of investment ....................... 53 -- CO2 contract acquisitions ........................................................... -- (4,702) Other, net .......................................................................... (209) (13) Proceeds from sale of assets ........................................................ 1,581 82 -------- -------- Net cash used in investing activities .................................................. (17,367) (9,126) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Net borrowings of debt .............................................................. 17,300 8,000 Credit facility issuance fees ....................................................... -- (839) Other, net .......................................................................... 172 -- Distributions to common unitholders ................................................. (4,191) (4,192) Distributions to General Partner .................................................... (86) (86) -------- -------- Net cash provided by financing activities .............................................. 13,195 2,883 -------- -------- Net decrease in cash and cash equivalents .............................................. 71 (1,964) Cash and cash equivalents at beginning of year ......................................... 2,078 2,869 -------- -------- Cash and cash equivalents at end of period ............................................. $ 2,149 $ 905 ======== ========
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 nine months ended September 30, 2005... -- 2,859 58 2,917 Distributions to partners during the nine months ended September 30, 2005 .................................... -- (4,191) (86) (4,277) ----- ------- ---- ------- Partners' capital at September 30, 2005 .................. 9,314 $42,994 $885 $43,879 ===== ======= ==== =======
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%, of which 0.7 million units (7.4%) are owned by our general partner, Genesis Energy, Inc. Our general partner also owns all of our 2% general partner interest. Our general partner is owned by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc. 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 (i) our consolidated financial position as of September 30, 2005 and December 31, 2004, (ii) our consolidated results of operations and changes in comprehensive income for the three and nine months ended September 30, 2005 and 2004, (iii) our consolidated cash flows for the nine months ended September 30, 2005 and 2004, and (iv) our consolidated changes in partners' capital for the nine months ended September 30, 2005. 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, because we are a "pass-through" entity for federal income tax purposes, meaning our income will be taxable directly to the partners holding partnership interests in the Partnership. 2. NEW ACCOUNTING PRONOUNCEMENTS In September 2005, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached consensus in 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 requiring 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. This requirement is effective for new arrangements entered into after March 31, 2006. If this requirement had been effective for the three and nine months ended September 30, 2005 and 2004, our reported crude oil gathering and marketing revenues from unrelated parties and our reported crude oil costs from unrelated parties would be reduced by the amounts shown in parenthetical notations on the consolidated statements of operations. We do not expect that the adoption of Issue 04-13 will have a material effect on our financial position, results of operations or cash flows. 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 -7- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS statement is effective for us 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 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. In May 2005, the FASB issued Statement of Financial Standards No. 154, "Accounting Changes and Error Corrections" (SFAS 154). This statement establishes new standards on the accounting for and reporting of changes in accounting principles and error corrections. SFAS 154 requires retrospective application to the financial statements of prior periods for all such changes, unless it is impracticable to do so. SFAS 154 is effective for us in the first quarter of 2006. 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 September 30, 2005, the components of the net investment in direct financing leases were as follows (in thousands): Total minimum lease payments to be received................... $ 9,707 Estimated residual values of leased property (unguaranteed)... 1,287 Less: Unearned income......................................... (4,395) ------- Net investment in direct financing leases..................... $ 6,599 =======
At September 30, 2005, minimum lease payments to be received for each of the five succeeding fiscal years are $1.2 million per year. -8- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. INVESTMENT IN T&P SYNGAS SUPPLY COMPANY On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply Company (T&P Syngas), a Delaware general partnership, for $13.4 million in cash from a subsidiary of ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. owns the remaining 50% partnership interest in T&P Syngas. We paid for our interest in T&P Syngas with proceeds from our credit facilities. T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas. That 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. Praxair operates the facility. We are accounting for our 50% ownership in T&P Syngas under the equity method of accounting. T&P Syngas is managed by a management committee comprised of representatives from each partner, therefore we share equally with Praxair in the control over the partnership. We reflect in our consolidated statements of operations our equity in T&P Syngas' net income, net of the amortization of the excess of our investment over our share of partners' capital of T&P Syngas. We paid $4.0 million more for our interest in T&P Syngas than our share of partners' capital on the balance sheet of T&P Syngas at the date of the acquisition. This excess amount of the purchase price over the equity in T&P Syngas is being amortized using the straight-line method over the remaining useful life of the assets of T&P Syngas of eleven years. Our consolidated statements of operations for the three and nine months ended September 30, 2005 included $97,000 and $436,000, respectively, as our share of the earnings of T&P Syngas for the period beginning April 1, 2005, reduced by amortization of the excess purchase price of $89,000 and $176,000, for the three and nine months, respectively. The table below reflects summarized financial information for T&P Syngas at September 30, 2005, for the period since we acquired our interest in T&P Syngas.
Six Months Ended September 30, 2005 ------------------ (in thousands) Revenues ................................. $ 1,919 Operating expenses and depreciation ...... (1,054) Other income ............................. 6 ------- Net income ............................... $ 871 =======
September 30, 2005 ------------------ (in thousands) Current assets ........................... $ 1,449 Non-current assets ....................... 16,808 ------- Total assets ............................. $18,257 ======= Current liabilities ...................... $ 490 Partners' capital ........................ 17,767 ------- Total liabilities and partners' capital .. $18,257 =======
The following pro forma information represents the effects on our consolidated statements of operations assuming the investment in T&P Syngas had occurred at the beginning of each period presented: -9- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2005 2004 2005 2004 -------- -------- -------- -------- (in thousands, except per unit amounts) Revenues ........................................ $300,577 $250,736 $814,321 $681,755 Operating (loss) income ......................... $ (109) $ (156) $ 3,740 $ 720 Equity in earnings of T&P Syngas ................ $ 8 $ 162 $ 420 $ 452 Net interest expense ............................ $ (540) $ (382) $ (1,624) $ (1,241) Income from continuing operations ............... (641) (377) 2,536 (70) Net (loss) income ............................... $ (596) $ (412) $ 2,944 $ (389) Basic and diluted net income (loss) per Common Unit (Loss) income from continuing operations ................................... $ (0.06) $ (0.04) $ 0.27 $ (0.01) Income (loss) from discontinued operations ................................... 0.00 0.00 0.03 (0.03) -------- -------- -------- -------- Net (loss) income ............................ $ (0.06) $ (0.04) $ 0.30 $ (0.04) ======== ======== ======== ========
The acquisition of T&P Syngas occurred April 1, 2005, so the pro forma results in the table above are the same as the actual results for the three months ended September 30, 2005. 5. DEBT We have a $100 million credit facility comprised of a $50 million revolving line of credit for acquisitions and a $50 million working capital revolving facility. The working capital portion of the credit facility has a $15 million sublimit for loans with the remainder of the $50 million available for letters of credit. In total we may have up to $65 million in loans under our credit facility. At September 30, 2005, we had $11.8 million in loans and $5.8 million in letters of credit (primarily for crude oil purchases in September 2005) outstanding under the working capital portion and $20.8 million outstanding under the acquisition portion of our credit facility. At September 30, 2005, the weighted average interest rate on the debt was 7.36%. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 1, 2008. The aggregate amount that we may have outstanding at any time under the working capital portion of our credit facility is subject to a borrowing base calculation. The borrowing base is limited to $50 million and is calculated monthly. At September 30, 2005, the borrowing base was $50.0 million. The remaining amount available for borrowings at September 30, 2005 was $3.2 million under the working capital portion and $29.2 million under the acquisition portion of the credit facility. Certain restrictive covenants of the credit facility limit our ability to make distributions to our unitholders and our general partner. The credit facility requires we maintain a cash flow coverage ratio of at least 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 September 30, 2005, the calculation resulted in a ratio of 1.1 to 1.0. Our 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 September 30, 2005, the result of this calculation was $10.3 million. If we meet these covenants, we are otherwise not limited by our credit facility in making distributions. 6. 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%. Our general partner owns all of our general partner interest, all of the 0.01% general partner interest in GCOLP (which is reflected as a minority interest in the consolidated balance sheet at September 30, 2005) and operates our business. -10- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 the first nine months of 2005 and in 2004, we paid a regular quarterly distribution of $0.15 per unit ($1.4 million in total per quarter). We have declared a $0.16 per unit distribution for the third quarter of 2005, payable on November 14, 2005 to unitholders of record on November 4, 2005. Our general partner is entitled to receive 2% of our distributions plus 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 September 30, 2005. Net Income Per Common Unit The following table sets forth the computation of basic net income per common unit.
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2005 2004 2005 2004 ------ ------ ------ ------ (in thousands, except per unit amounts) Numerators for basic and diluted net income per common unit: (Loss) income from continuing operations ................... $ (641) $ (359) $2,599 $ 19 Less general partner 2% ownership ....................... (13) (8) 52 -- ------ ------ ------ ------ (Loss) income from continuing operations available for common unitholders ...................................... $ (628) $ (351) $2,547 $ 19 ====== ====== ====== ====== Income (loss) from discontinued operations ................. $ 45 $ (35) $ 318 $ (319) Less general partner 2% ownership .......................... 1 -- 6 (6) ------ ------ ------ ------ Income (loss) from discontinued operations available for common unitholders .................................. $ 44 $ (35) $ 312 $ (313) ====== ====== ====== ====== Denominator for basic and diluted per Common Unit - weighted average number of Common Units outstanding ................. 9,314 9,314 9,314 9,314 ====== ====== ====== ====== Basic and diluted net income (loss) per Common Unit: (Loss) income from continuing operations ................... $(0.06) $(0.04) $ 0.28 $ 0.00 Income (loss) from discontinued operations ................. 0.00 0.00 0.03 (0.03) ------ ------ ------ ------ Net (loss) income .......................................... $(0.06) $(0.04) $ 0.31 $(0.03) ====== ====== ====== ======
7. 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 sales - the sale, under long-term contracts, of CO2 acquired under a volumetric production payment to industrial customers. -11- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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.
Crude Oil Gathering and Pipeline CO2 Marketing Transportation Sales Total ------------- -------------- ------- -------- (in thousands) Three Months Ended September 30, 2005 Revenues: External Customers ......................... $291,074 $ 5,989 $ 2,523 $299,586 Intersegment (a) ........................... -- 991 -- 991 -------- ------- ------- -------- Total revenues of reportable segments ...... $291,074 $ 6,980 $ 2,523 $300,577 ======== ======= ======= ======== Segment margin excluding depreciation and amortization (b) ........................ $ 1,053 1,885 $ 1,680 $ 4,618 Capital expenditures ....................... $ 38 $ 555 $ -- $ 593 Maintenance capital expenditures ........... $ 7 $ 407 $ -- $ 414 Three Months Ended September 30, 2004 Revenues: External Customers ......................... $244,377 $ 2,877 $ 2,295 $249,549 Intersegment (a) ........................... -- 1,187 -- 1,187 -------- ------- ------- -------- Total revenues of reportable segments ...... $244,377 $ 4,064 $ 2,295 $250,736 ======== ======= ======= ======== Segment margin excluding depreciation and amortization (b) ........................ $ 948 2,601 $ 1,543 $ 5,092 Capital expenditures ....................... $ 56 $ 4,173 $ 4,723 $ 8,952 Maintenance capital expenditures ........... $ 56 $ 161 $ -- $ 217 Nine Months Ended September 30, 2005 Revenues: External Customers ......................... $785,774 $18,579 $ 7,371 $811,724 Intersegment (a) ........................... -- 2,597 -- 2,597 -------- ------- ------- -------- Total revenues of reportable segments ...... $785,774 $21,176 $ 7,371 $814,321 ======== ======= ======= ======== Segment margin excluding depreciation and amortization (b) ........................ $ 2,391 7,136 $ 4,962 $ 14,489 Capital expenditures ....................... $ 315 $ 5,157 $ -- $ 5,472 Maintenance capital expenditures ........... $ 55 $ 1,070 $ -- $ 1,125 Net fixed and other long-term assets (c) ... $ 6,140 $35,284 $24,374 $ 65,798 Nine Months Ended September 30, 2004 Revenues: External Customers ......................... $663,245 $ 9,346 $ 6,275 $678,866 Intersegment (a) ........................... -- 2,889 -- 2,889 -------- ------- ------- -------- Total revenues of reportable segments ...... $663,245 $12,235 $ 6,275 $681,755 ======== ======= ======= ======== Segment margin excluding depreciation and amortization (b) ........................ $ 3,898 6,111 $ 4,244 $ 14,253 Capital expenditures ....................... $ 131 $ 5,577 $ 4,723 $ 10,431 Maintenance capital expenditures ........... $ 131 $ 496 $ -- $ 627 Net fixed and other long-term assets (c) ... $ 6,376 $31,465 $27,159 $ 65,000
-12- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 income from continuing operations for the periods presented is as follows:
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2005 2004 2005 2004 ------ ------ ------- ------- (in thousands) Segment margin excluding depreciation and amortization ... $4,618 $5,092 $14,489 $14,253 General and administrative expenses ...................... 3,210 2,639 6,536 7,825 Depreciation, amortization and impairment ................ 1,601 2,599 4,695 5,773 Net gain on disposal of surplus assets ................... (84) 10 (482) (65) ------ ------ ------- ------- Operating income from continuing operations .............. $ (109) $ (156) $ 3,740 $ 720 ====== ====== ======= =======
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. 8. 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. Transactions with Denbury and our General Partner
Nine Months Ended September 30, ----------------- 2005 2004 ------- ------- (in thousands) Crude oil purchases from Denbury ....................... $ 3,422 $76,491 Crude oil sales to Denbury ............................. $ 22 $ -- Truck transportation services provided to Denbury ...... $ 591 $ 23 Pipeline transportation services provided to Denbury ... $ 2,858 $ 277 Payments received under direct financing leases from Denbury ............................................. $ 890 $ -- Pipeline transportation income portion of direct financing lease fees ................................ $ 521 $ -- Pipeline monitoring services provided to Denbury ....... $ 22 $ 15 Directors' fees paid to Denbury ........................ $ 90 $ 90 CO2 transportation services provided by Denbury ........ $ 2,296 $ 1,954 Purchase of CO2 volumetric payment from Denbury ........ $ -- $ 4,663 Operations, general and administrative services provided by our general partner ..................... $11,487 $10,129 Distributions to our general partner on its limited partner units and general partner interest .......... $ 396 $ 396
Sales and Purchases of Crude Oil 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 own account. Denbury pays us a fee for this trucking -13- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS service that varies with the distance the crude oil is trucked. 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. We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven CO2 pipeline and recorded pipeline transportation income from these arrangements. See Note 3. We also provide pipeline monitoring services to Denbury. This revenue is included in pipeline revenues in the statement of operations. Directors' Fees We pay 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 2004 and 2003. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2 for us to our customers. Operations, General and Administrative Services We do not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services. Amounts due to and from Related Parties At September 30, 2005 and December 31, 2004, we owed Denbury $1.6 million and $1.2 million, respectively, for purchases of crude oil and CO2 transportation charges. Denbury owed us $0.5 million and $0.4 million for transportation services at September 30, 2005 and December 31, 2004, respectively. We owed our general partner $0.6 million at September 30, 2005, for administrative services. We had advanced $0.1 million to our general partner at December 31, 2004 for administrative services. Financing Our general partner, a wholly owned subsidiary of Denbury, guarantees our obligations under our 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. 9. MAJOR CUSTOMERS AND CREDIT RISK Due to the nature of our crude oil operations, a disproportionate percentage of our trade receivables constitute obligations of oil companies.. 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 integrated and large independent energy companies 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. and Shell Oil Company accounted for 27% and 12% of total revenues for the first nine months of 2005, respectively. Occidental Energy Marketing, Inc. and Marathon Ashland Petroleum LLC accounted for 18% and 14% of total revenues for the nine months ended September 30, 2004, respectively. The majority of the revenues from these customers in both periods relate to our crude oil gathering and marketing operations. -14- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. SUPPLEMENTAL CASH FLOW INFORMATION Cash received by the Partnership for interest was $38,000 and $37,000 for the nine months ended September 30, 2005 and 2004, respectively. Payments of interest and commitment fees were $931,000 and $196,000 for the nine months ended September 30, 2005 and 2004, respectively. At September 30, 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. 11. 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, although we have the flexibility to enter into arrangements with a longer term. 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 the fair value of derivatives that are 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. The effective portion of unrealized gains or losses on derivative transactions qualifying as cash flow hedges are reflected in other comprehensive income. Derivative transactions qualifying as fair value hedges are evaluated for hedge effectiveness and the resulting hedge ineffectiveness is recorded as a gain or loss in the consolidated statements of operations. We review our contracts to determine if the contracts meet the definition of derivatives pursuant to SFAS 133. At September 30, 2005, we had futures contracts on the NYMEX that were considered free-standing derivatives that are accounted for at fair value. The fair value of these contracts was determined based on the closing price for such contracts on the NYMEX on September 30, 2005. We marked these contracts to fair value at September 30, 2005. During the three months ended September 30, 2005, we recorded a loss of $8,000 related to derivative transactions, which are included in the consolidated statements of operations under the caption "Crude Oil Costs". For the nine month period, these derivative transactions had no effect on earnings. At September 30, 2005, we had futures contracts on the NYMEX that qualified as derivatives and were formally documented and designated as fair value hedges of inventory. During the three and nine months ended September 30, 2005, we recognized gains, due to hedge ineffectiveness, on the fair value hedge of 60,000 barrels of inventory totaling $155,000 and $147,000, respectively. These gains are included in the caption "Crude Oil Costs" in the consolidated statements of operations. The time value component of the derivative gain or loss excluded from the assessment of hedge effectiveness was not material. The consolidated balance sheet at September 30, 2005 includes a reduction in other current assets of $58,000 as a result of these derivative transactions. At September 30, 2004, we had one swap contract that was considered a free-standing derivative that was accounted for at fair value. The fair value of this contract was determined based on quoted prices from independent sources. We marked this contract to fair value at September 30, 2004, and recorded income of $16,000 which is included in the consolidated statements of operations under the caption "Crude Oil Costs". -15- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We determined that the remainder of our derivative contracts qualified for the normal purchase and sale exemption and were designated and documented as such at September 30, 2005 and December 31, 2004. 12. CONTINGENCIES Guarantees We have guaranteed $3.5 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 our credit facility related to borrowings and letters of credit. Borrowings at September 30, 2005 were $32.6 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 $0.7 million during the remainder of 2005 and approximately $0.3 million in 2006 for testing, repairs 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. Pennzoil-Quaker State Company (PQS) was seeking from us 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 crude oil we sold to PQS 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 us and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against us is without merit and intend to vigorously defend ourselves in this matter. We currently believe that this matter will not have a material financial effect on our financial position, results of operations, or cash flows. Environmental In 1992, Howell Crude Oil Company entered into a sublease with Koch Industries, Inc., covering a one acre tract 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 the Jay Station as a crude oil trucking station until 2003. Koch has indicated that it has incurred certain investigative and/or other costs, for which Koch alleges some or all should be reimbursed by us, under the indemnification provisions of the sublease for environmental contamination on the site and surrounding areas. Koch has also alleged that we are responsible for future environmental obligations relating to the Jay Station. Howell was acquired by Anadarko Petroleum Corporation (Anadarko) in 2002. During the second quarter of 2005, we entered into a joint defense and cost allocation agreement with Anadarko. Under the terms of the joint allocation agreement, we agreed to reasonably cooperate with each other to address any liabilities or defense costs with respect to the Jay Station. Additionally under the Joint Allocation Agreement, Anadarko will be responsible for sixty percent of the costs related to any liabilities or defense costs incurred with respect to contamination at the Jay Station. -16- GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We were formed in 1996 by the sale and contribution of assets from Howell and Basis Petroleum, Inc.. Anadarko's liability with respect to the Jay Station is derived largely from contractual obligations entered into upon our formation. We believe that Basis has contractual obligations under the same formation agreements. We are preparing a formal demand seeking Basis' share of potential liabilities and defense costs with respect to Jay Station. We have contacted the appropriate state regulatory agencies regarding developing a plan of remediation for certain affected soils at the Jay Station. It is possible that we will also need to develop a plan for other affected soils and/or affected groundwater. Through the third quarter of 2005, we have accrued an estimate of our share of liability for this matter in the amount of $0.5 million. If we are required to remediate the site on a more extensive basis than contemplated by our estimate, we could incur additional obligations of up to $0.8 million. The time period over which our liability would be paid is uncertain and could be several years. This liability may decrease if indemnification and/or cost reimbursement is obtained by us for Basis' potential liabilities with respect to this matter. At this time, our estimate of potential obligations does not assume any specific amount contributed on behalf of the Basis obligations, although we believe that Basis is responsible for a significant part of these potential obligations. 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. We do not expect such matters presently pending to have a material adverse effect on our financial position, results of operations or cash flows. 13. SUBSEQUENT EVENTS On October 11, 2005, we acquired a third volumetric production payment and certain related contracts from Denbury for $14.4 million in cash. Pursuant to that acquisition, Denbury assigned to us an interest in 80.0 Bcf of CO2 under a volumetric production payment and Denbury's existing long-term CO2 supply agreements with two of its industrial customers. The terms of the industrial sales contracts include minimum take-or-pay volumes and maximum delivery volumes. Denbury will also provide processing and transportation services for a fee. We funded the purchase with proceeds from our credit facility. On October 24, 2005, the Board of Directors of the general partner declared a cash distribution of $0.16 per unit for the quarter ended September 30, 2005. The distribution will be paid November 14, 2005, to our general partner and all common unitholders of record as of the close of business on November 4, 2005. -17- 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 7 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, the replacement with the amount recognized as our equity in the income of joint ventures with distributions received from those ventures, 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 sales. 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. We also report our share of the earnings of our equity investee, T&P Syngas Supply Company in which we acquired a 50% interest on April 1, 2005. Our primary goal is to generate Available Cash before Reserves for our unitholders. Our Available Cash after Reserves is distributed quarterly to our unitholders. During the third quarter of 2005, the Available Cash before Reserves that we generated was less than our distribution, so we drew upon reserves that we built in prior periods. We generated net income for the nine months of 2005 from a combination of four main sources. These sources included the results of our operating activities, the sale of idle assets, our equity in the earnings from our investment in T&P Syngas, and the effects of decreasing the liability under our incentive compensation plan. 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 exercise. These rights vest over several years. 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. The unit price then increased in the second quarter of 2005 to $9.39, for which we provided a liability of $43,000. In the third quarter, the unit price increased to $11.60. Therefore, for the third quarter of 2005 we increased our liability by $0.7 million. In total, for the nine months ended September 30, 2005, we have recorded a net credit $0.5 million. -18- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ACQUISITIONS IN 2005 GAS PIPELINE TRANSPORTATION 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 with proceeds from our credit facility. 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 $13.4 million. We acquired our interest from TCHI Inc., a wholly owned subsidiary of ChevronTexaco Global Energy Inc. Praxair Hydrogen Supply, Inc. (Praxair) owns the other 50% interest in the partnership. T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas. That 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. Praxair operates the facility. 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 in the amount of cash on hand in excess of $100,000. In July 2005 and October 2005, we received distributions of $0.3 million and $0.5 million from T&P Syngas related to the second and third quarters of 2005, respectively. We financed our T&P Syngas interest acquisition with proceeds from our credit facility. THIRD VOLUMETRIC PRODUCTION PAYMENT On October 11, 2005, we acquired a third volumetric production payment and certain related contracts from Denbury for $14.4 million in cash. Pursuant to that acquisition, Denbury assigned to us an interest in 80.0 Bcf of CO2 under a volumetric production payment and Denbury's existing long-term CO2 supply agreements with two of its industrial customers. The terms of the industrial sales contracts include minimum take-or-pay volumes and maximum delivery volumes. Denbury will also provide processing and transportation services for a fee. We funded the purchase with proceeds from our credit facility. In accordance with our procedures for evaluating and valuing material acquisitions with Denbury, our Special Conflicts Committee of our Board of Directors engaged legal counsel and obtained a fairness opinion from an independent financial advisor regarding the acquisition of the third volumetric production payment. The opinion we received stated the transaction was fair to our unitholders. 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 commodity price (for purchases and sales) of crude oil do not necessarily bear a relationship to segment margin as those prices normally impact revenues and costs of sales by approximately equivalent amounts. Because period-to-period variations in revenues and costs of sales are not -19- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS generally meaningful in analyzing the variation in segment margin for our 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. Those 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. Operating results from continuing operations for our crude oil gathering and marketing segment were as follows:
Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------- 2005 2004 2005 2004 -------- -------- -------- -------- (in thousands, except volumes per day) Revenues ................................................... $291,074 $244,377 $785,774 $663,245 Crude oil costs ............................................ 286,608 239,954 772,387 649,652 Field operating costs ...................................... 4,082 3,473 12,097 9,711 Change in fair value of derivatives ........................ (669) 2 (1,101) (16) -------- -------- -------- -------- Segment margin .......................................... $ 1,053 $ 948 $ 2,391 $ 3,898 ======== ======== ======== ======== Volumes per day from continuing operations: Crude oil wellhead - barrels ............................ 37,213 46,676 39,818 48,078 Crude oil total - barrels (includes wellhead barrels) ... 51,639 61,919 55,211 62,556 Crude oil truck transported only - barrels .............. 2,212 1,307 3,335 760
Three Months Ended September 30, 2005 Compared with Three Months Ended September 30, 2004 Crude oil gathering and marketing segment margins from continuing operations increased $0.1 million for the three months ended September 30, 2005, as compared to the three months ended September 30, 2004. Segment margin increased primarily due to two factors with two other factors partially offsetting the increase. These four factors were as follows: - A $0.7 million unrealized gain from a fair value hedge of inventory. This gain resulted from an 18% increase in crude oil market prices during the 2005 third quarter. - A $0.1 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 July and August of 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 $0.6 million increase in field operating costs, related to higher fuel costs and higher personnel costs. Fuel costs have increased approximately $0.67 per gallon, or 38%, since the 2004 quarter. 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. - A 17% decrease in wellhead, bulk and exchange purchase volumes combined with an 18% increase in the difference between the average sales and purchase prices for the crude oil, resulting in a $0.1 million reduction in segment margin. -20- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004 For the nine month period, crude oil gathering and marketing segment margins from continuing operations decreased $1.5 million in 2005 from the prior year period. Contributing to this reduction in segment margin were the following two factors that reduced segment margin: - A $2.4 million increase in field operating costs. $0.4 million of this increase is attributable to a reserve we recorded for 40% of the expected costs to remediate Jay Station. (See additional discussion at Note 12 to the Consolidated Financial Statements.) The majority of the remaining increase of $2.0 million over the 2004 third quarter related again to higher fuel costs, higher employee costs and the costs related to additional tractor/trailers we leased in the third quarter of 2004. - A 7,345 barrel per day decrease in purchased volumes. This 12% decrease, offset by a slight increase in the average difference between the sales price and purchase price of crude oil reduced segment margin by $1.1 million. Partially offsetting the decrease from higher field costs and lower volumes were increases in three factors. These factors were: - A $0.7 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 $1.1 million unrealized gain from a fair value hedge of inventory. This gain resulted from an approximate 35% increase in crude oil market prices since we acquired the inventory in the second quarter of 2005. - A $0.2 million decrease in credit costs related to crude oil transactions. Outlook Based on past experience and knowledge of assets in the crude oil gathering and marketing segment, we continue to expect volatility from this segment, which we attempt to mitigate in various ways. Effectively managing relationships with suppliers; managing inventory; controlling field costs; and improving operational efficiency in the field are some steps we take to mitigate volatility. PIPELINE TRANSPORTATION OPERATIONS We operate three crude oil common carrier pipeline systems in a five state area. We refer to these pipelines as our Texas System, Mississippi System and Jay System. Average volumes shipped on these systems for the three months and nine months ended September 30, 2005 and 2004 are as follows:
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- -------------------------------- 2005 2004 2005 2004 ------ ------ ------ ------ (barrels per day) Texas......... 33,536 31,463 32,213 37,757 Jay........... 11,704 12,712 13,909 14,698 Mississippi... 14,924 13,369 15,568 11,947
Volumes on our Texas System averaged 33,536 barrels per day during the third 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. -21- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This tariff declined to $0.20 per barrel in November 2004. Substantially all 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 due to Denbury's CO2 tertiary recovery activities, 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 was injected into 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. -22- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Operating results from continuing operations for our pipeline transportation segment were as follows:
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2005 2004 2005 2004 ------- ------- ------- ------- (in thousands, except volumes per day) Crude oil tariffs and revenues from direct financing leases of crude oil pipelines ................................... $ 3,314 $ 3,102 $10,096 $ 9,666 Sales of crude oil pipeline loss allowance volumes .......... 1,158 854 3,456 2,449 Revenues from direct financing leases of CO2 pipelines ...... 88 -- 271 -- Tank rental reimbursements and other miscellaneous revenues.. 134 108 432 120 ------- ------- ------- ------- Total revenues from crude oil and CO2 tariffs, including revenues from direct financing leases .................... 4,694 4,064 14,255 12,235 Revenues from natural gas tariffs and sales ................. 2,286 -- 6,921 -- Natural gas purchases ....................................... (2,178) -- (6,590) -- Pipeline operating costs .................................... (2,917) (1,463) (7,450) (6,124) ------- ------- ------- ------- Segment margin ........................................... $ 1,885 $ 2,601 $ 7,136 $ 6,111 ======= ======= ======= ======= Volumes per day from continuing operations: Crude oil pipeline - barrels ............................. 60,164 57,544 61,690 64,402
Three Months Ended September 30, 2005 Compared with Three Months Ended September 30, 2004 Pipeline segment margin decreased $0.7 million to $1.8 million for the three months ended September 30, 2005, as compared to the three months ended September 30, 2004. The decrease in pipeline segment margin is primarily attributable to an increase in pipeline operating costs of $1.5 million, offset partially by an increase of $0.6 million in crude oil and CO2 tariff revenues. Also offsetting the higher costs were $0.2 million of net profit from the sales of natural gas. The fluctuation in operating costs is the result of increased costs related to pipeline integrity management repairs in 2005 and the effects on the 2004 period of a reversal of an accrual related to a pipeline we were allowed to abandon rather than remove. Our pipeline integrity costs in the third quarter of 2005 totaled $0.7 million. Those costs related to the last major section of pipeline that needed to be tested for the first time. The accrual that was reversed in the third quarter of 2004 reduced that period's pipeline operating costs by $0.5 million. The remaining $0.2 million increase in pipeline operating costs in the 2005 quarter resulted from increased costs for numerous items including liability insurance, maintenance projects and various operational costs. Crude oil and CO2 tariff revenues increased $0.2 million in the 2005 third quarter compared to the prior year period due to the combination of higher tariffs and higher volumes. Volumes on our pipelines were affected briefly by hurricanes in both periods, but overall volumes increased when comparing the quarters. The effects of lower tariffs on the Texas 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 $0.3 million in the 2005 third quarter as a result of higher crude oil market prices. The CO2 pipeline did not exist in the third quarter of 2004, and the natural gas gathering pipelines were acquired in the first quarter of 2005. Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004 For the nine months ended September 30, 2005, pipeline segment margin increased $1.0 million or 17%, as compared to the same period in 2004. Revenues from crude oil and CO2 tariffs and related sources added $2.0 million of the increase for the period and $0.3 million of the increase resulted from net profit from natural gas transportation and sales. Pipeline operating cost increases offset $1.3 million of the revenue increases. -23- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Crude oil pipeline volumes increased slightly between the two periods. The hurricanes in the third quarter of 2005 reduced volumes on the Jay System, but the decline was offset by increases on the other two crude oil pipelines. Overall, crude oil pipeline tariffs, including income from direct financing leases of crude oil pipelines increased $0.4 million between the nine month periods due primarily to higher tariffs on the Mississippi System. Higher market prices for crude oil added $1.0 million to pipeline loss allowance revenues between the periods, and tariffs from the CO2 pipeline added another $0.3 million. The tank rental agreement on the Texas System combined with other miscellaneous revenues added $0.3 million to tariff revenues between the periods. Operating costs increased $1.3 million. In 2004, as well as in 2005, we incurred costs for regulatory testing and repairs resulting from that testing. Those costs were approximately $0.3 million greater in the 2005 period. Operational costs for personnel, contract services, liability insurance and equipment maintenance accounted for most of the remaining increase. Outlook Volumes on the Texas System may continue to fluctuate as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's pipeline systems. We have completed our integrity testing on that system. 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, that re-development of older fields and any related increase in production, could 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. Our agreement with Denbury provides for a minimum capacity charge that will provide $0.6 million of annual payments to us with a commodity charge for volumes in excess of a threshold volume through December 2012. The segments of crude oil pipeline we constructed to Denbury's Olive and Brookhaven fields also have agreements providing for minimum capacity charges with commodity charges for volumes in excess of threshold volumes through 2013. The payments under these crude oil transportation agreements should 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. As a result of new production in the area surrounding the Jay System, volumes have stabilized on that system. Historically, producing wells in the area have had rapidly declining future production curves, therefore we do not know if this new production will be sufficient to continue to offset declining production from existing wells in the area. Should the production surrounding the Jay System decline such that it becomes uneconomical to continue to operate the pipeline in crude oil service, 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. -24- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CARBON DIOXIDE (CO2) OPERATIONS In November 2003, we acquired a volumetric production payment, or 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 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 and 2004 under these contracts (including volumes sold by Denbury on the contracts we acquired in the third quarter of 2004) were as follows:
Quarter 2005 2004 ------- ------ ------ First 47,808 45,671 Second 51,049 51,164 Third 51,386 53,095 Fourth 48,217
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. 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 Sales segment were as follows:
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2005 2004 2005 2004 ------- ------- ------- ------- (in thousands, except volumes per day) Revenues ................................... $2,523 $2,295 $7,371 $6,275 CO2 transportation and other costs ......... 843 752 2,409 2,031 ------ ------ ------ ------ Segment margin .......................... $1,680 $1,543 $4,962 $4,244 ====== ====== ====== ====== Volumes per day from continuing operations: CO2 Sales - Mcf ......................... 51,386 48,634 50,094 44,337
-25- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Three Months Ended September 30, 2005 Compared with Three Months Ended September 30, 2004 The increase in volume in the third quarter of 2005 was due to the effects of the additional contracts acquired in September 2004. The average revenue per Mcf sold increased by $0.02, due to inflation adjustments in the contracts and variations in the volumes sold under each contract. Transportation costs for the CO2 on Denbury's pipeline increased by $0.1 million when comparing the third quarters. This increase is attributable to the increased volume and the effect of the annual inflation adjustment factor in the rate paid to Denbury. The rate in the third quarter of 2005 averaged $0.1705 per Mcf as compared to $0.1623 per Mcf in the 2004 period Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004 For the nine month period, the increased revenues are attributable to the same effects as in the 2004 period. Volumes increased due to the additional contracts, and the average sales price increased by $0.02 per Mcf. The rate for transportation costs increased from an average of $0.1608 per Mcf to $0.1679 per Mcf, due to the inflation provision in the transportation contract. Outlook We acquired an 80 Bcf volumetric payment from Denbury in October 2005 at a cost of $14.4 million in cash. We also acquired two additional long-term sales contracts with industrial customers. DISCONTINUED OPERATIONS In the first nine months of 2005, we sold assets that were no longer in service related to the Texas operations that we sold in 2003, receiving $0.3 million and recognizing a gain of $0.3 million. During the first nine months of 2004, we incurred costs totaling $0.3 million related to the dismantlement of assets that we abandoned in 2003. OTHER COSTS AND INTEREST General and administrative expenses. General and administrative expenses were as follows:
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2005 2004 2005 2004 ------ ------ ------ ------ (in thousands) Expenses excluding effect of stock appreciation rights plan .. $2,465 $2,667 $7,077 $7,261 Stock appreciation rights plan expense (credit) .............. 745 (28) (541) 564 ------ ------ ------ ------ Total general and administrative expenses ................. $3,210 $2,639 $6,536 $7,825 ====== ====== ====== ======
Three Months Ended September 30, 2005 Compared with Three Months Ended September 30, 2004 General and administrative expenses increased by $0.6 million, however, the increase is attributable to our employee stock appreciation rights (SAR) 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. Between the end of the second quarter of 2005 and the end of the third quarter of 2005, the market price for our units rose $2.21, resulting in an increase in the liability under the SAR plan of $0.7 million. In the 2004 three month period, the market price did not change, resulting in a small credit to general and administrative expense. The remainder of our general and administrative expenses declined slightly between the two quarterly periods. -26- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Nine Months Ended September 30, 2005 Compared with Nine Months Ended September 30, 2004 For the nine month periods, general and administrative expenses decreased by $1.3 million, with $1.1 million of the decrease attributable to our employee stock appreciation rights plan. In the 2004 period, the market price for our common units rose so that we recorded a liability of $0.6 million. In the 2005 period, our unit price declined from $12.60 per unit at December 31, 2004 to $11.60 per unit at September 30, 2005. As a result, a reduction in the accrual was recorded, resulting in a total difference of $1.1 million. General and administrative expenses, excluding the effects of our stock appreciation rights (SAR) plan, decreased by $0.2 million between the nine month periods. We did not incur costs in the 2005 period for assistance in the initial documentation of our internal controls, although this reduction was partially offset by higher employee costs. Equity in T&P Syngas. On April 1, 2005, we acquired a 50% interest in T&P Syngas. Our share of the earnings of T&P Syngas for the second and third quarters of 2005 was $436,000. We are amortizing the excess of the price we paid for our interest in T&P Syngas over our share of the equity of T&P Syngas over the remaining useful life of the assets of T&P Syngas. This excess of $4.0 million is being amortized over eleven years. The effect of this amortization was to reduce the amount we recorded as our equity in T&P Syngas by $176,000. In July 2005, we received a distribution from T&P Syngas of $313,000 related to the second quarter. In October 2005, we received a distribution of $510,000 related to the third quarter of 2005. Interest expense, net. Interest expense, net was as follows:
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2005 2004 2005 2004 ---- ---- ------ ---- (in thousands) Interest expense, including commitment fees ... $461 $134 $1,174 $512 Amortization of facility fees ................. 89 78 265 226 Interest income ............................... (10) (9) (38) (37) ---- ---- ------ ---- Net interest expense ....................... $540 $203 $1,401 $701 ==== ==== ====== ====
In the third quarter and first nine months of 2005, we had more debt outstanding and market interest rates rose. Additionally in June 2004, we increased the size of our credit facility resulting in increased commitment fees. These factors contributed to an increase in interest expense in these periods as compared to the same periods in 2004. In the 2005 third quarter, our average outstanding balance of bank debt was $18.6 million higher than in the 2004 third quarter and our average interest rate was 1.9% greater than in the 2004 period. The debt increase is attributable primarily to acquisitions in the 2005 period. In the 2005 nine month period, our average outstanding balance of debt was $14.5 million higher than in the 2004 period and our average interest rate was 1.8% greater than the 2004 period. Gain on disposal of surplus assets. In the first nine months of 2005, we sold the Liberty to Maryland segment of our Mississippi pipeline. This segment had been out-of-service since February 2002. Additionally, we sold an idle site in Houma, Louisiana and other surplus assets. We received $1.3 million from the sales of these assets and realized gains totaling $0.5 million. LIQUIDITY AND CAPITAL RESOURCES CAPITAL RESOURCES We have a $100 million credit facility comprised of a $50 million revolving line of credit for acquisitions and a $50 million working capital revolving facility. The working capital portion of the credit facility has a $15 million sublimit for loans with the remainder of the $50 million available for letters of credit. In total we may have up to $65 million in loans outstanding under our credit facility. At September 30, 2005, we had $11.8 million in loans and $5.8 million in letters of credit outstanding under the working capital portion and $20.8 million -27- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS outstanding under the acquisition portion of our credit. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 1, 2008. The aggregate amount that we may have outstanding at any time in loans and letters of credit under the working capital portion of our credit facility is subject to a borrowing base calculation. The borrowing base is limited to $50 million and is calculated monthly. At September 30, 2005, the borrowing base was $50.0 million. The total amount available for borrowings at September 30, 2005 was $3.2 million under the working capital portion and $29.2 million under the acquisition portion of our credit facility. Certain restrictive covenants in the credit facility limit our ability to make distributions to our unitholders and the general partner. 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 September 30, 2005, the calculation resulted in a ratio of 1.1 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 September 30, 2005, the result of this calculation was $10.3 million. If we meet these covenants, we are otherwise not limited in making distributions. Our average daily outstanding balance under our credit facility during the first nine months of 2005 was $17.2 million. The average interest rate we paid during this same period was 7.13%. The average interest rate on our outstanding borrowings at September 30, 2005 was 7.36%. CAPITAL EXPENDITURES A summary of our capital expenditures in the nine months ended September 30, 2005 and 2004 is as follows:
Nine Months Ended September 30, ----------------- 2005 2004 ------- ------- (in thousands) Maintenance capital expenditures: Texas pipeline system ....................... $ 101 $ 109 Mississippi pipeline system ................. 961 370 Jay pipeline system ......................... 7 17 Crude oil gathering assets .................. 10 41 Administrative assets ....................... 46 90 ------- ------- Total maintenance capital expenditures ... 1,125 627 Growth capital expenditures: Mississippi pipeline system ................. 976 5,048 Natural gas gathering assets ................ 3,110 -- T&P Syngas Company investment ............... 13,418 -- CO2 contracts ............................... -- 4,723 Crude oil gathering assets .................. 260 33 ------- ------- Total growth capital expenditures ........ 17,764 9,804 ------- ------- Total capital expenditures ............ $18,889 $10,431 ======= =======
Maintenance capital expenditures in 2005 and 2004 included pipeline and station improvements in Mississippi to handle increased volumes. Texas pipeline maintenance capital expenditures related to corrosion control improvements. 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 nine months of 2004 related to the acquisition of right-of-way and the initial construction costs for the extensions of our crude oil pipeline and a CO2 pipeline to Denbury's Brookhaven field. -28- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The natural gas gathering assets were acquired from Multifuels in January 2005. The investment in T&P Syngas was made in April 2005. Crude oil gathering assets included a crude oil gathering pipeline to move oil from a producer's wellhead to a connection with a third party pipeline. 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 the remainder of 2005 will total to approximately $0.4 million. These expenditures are expected to relate primarily to our Mississippi System, including minor facility improvements and improvements to the pipeline as a result of integrity management test results and software and equipment updates in our corporate office. 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 will complete the repairs for the first 50% during the fourth quarter of 2005. In addition to our estimated capital expenditures, we expect to spend $0.5 million in the remainder of 2005 and $0.3 million in 2006 for pipeline integrity testing and repairs 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. 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. In addition, we acquired a third volumetric production payment in October 2005 for $14.4 million in cash. SOURCES OF FUTURE CAPITAL Our 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 September 30, 2005, we had $32.6 million outstanding under our credit facility, and $32.4 million available for borrowings. On October 11, 2005, we used $14.4 million of this availability to purchase a third volumetric production payment. 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 for our expansion will require funding through borrowings under our 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 and credit facilities. Our primary uses of cash flows are capital expenditures and distributions. A summary of our cash flows is as follows:
Nine Months Ended September 30, ------------------ 2005 2004 -------- ------- (in thousands) Cash provided by (used in): Operating activities ........ $ 4,243 $ 4,279 Investing activities ........ $(17,367) $(9,126) Financing activities ........ $ 13,195 $ 2,883
-29- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Operating. Net cash from operating activities for each period have been comprised of the following:
Nine Months Ended September 30, ----------------- 2005 2004 ------- ------- (in thousands) Net income (loss) ............................... $ 2,917 $ (300) Depreciation and amortization ................... 4,695 5,773 Gain on sales of assets ......................... (800) (65) Direct financing leases ......................... 369 -- Other non-cash items ............................ (799) 837 Changes in components of working capital, net ... (2,139) (1,966) ------- ------- Net cash from operating activities ........... $ 4,243 $ 4,279 ======= =======
Our operating cash flows are affected significantly by changes in items of working capital. Affecting all periods is the timing of capital expenditures and their effects on our recorded liabilities. 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 $95.4 million aggregate receivables on our consolidated balance sheet at September 30, 2005, approximately $94.0 million, or 98.5%, were less than 30 days past the invoice date. Investing. Cash flows used in investing activities in the first half of 2005 were $17.4 million as compared to $9.1 million in 2004 period. In 2005, we expended $5.4 million for property additions, including $3.1 million for the natural gas gathering assets acquired from Multifuels. We made an investment in T&P Syngas Supply Company utilizing $13.4 million. Offsetting these expenditures was the receipt of $1.6 million for the sale of idle assets. In 2004 we expended $4.5 million for property and equipment additions, and received $0.1 million from the sale of surplus assets. In 2004 we expended cash for the first phase of an addition to our Mississippi System and to begin construction on a new tank on the Mississippi System. We used $4.7 million to acquire a CO2 volumetric payment in 2004. Financing. In the first nine months of 2005, financing activities provided net cash of $13.2 million. We increased our borrowings by $17.3 million, primarily to fund the investment in T&P Syngas and the acquisition of the natural gas assets. We utilized $4.3 million of cash to make distributions to our partners. In the nine months of 2004, financing activities provided net cash of $2.9 million. Our outstanding debt increased $8.0 million. Distributions to our partners utilized $4.3 million. We also incurred $0.8 million of costs related to our new credit facility. 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 our 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). Beginning with the distribution for the third quarter of 2005 (payable on November 14, 2005), we have increased our distribution rate and will pay $0.16 per unit ($1.5 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 -30- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 $0.16 per unit for the fourth quarter of 2005. Our ability to increase distributions during 2006 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 three and nine months ended September 30, 2005, is as follows:
Three Nine Months Months Ended Ended September 30, September 30, 2005 2005 ------------- ------------- (in thousands) AVAILABLE CASH BEFORE RESERVES: Net (loss) income ...................................................... $ (596) $ 2,917 Depreciation and amortization .......................................... 1,601 4,695 Cash received from direct financing leases not included in income ...... 125 369 Cash proceeds in excess of gains on certain asset sales ................ 92 781 Distributions received or to be received from T&P Syngas in excess of equity recorded ........................................ 502 563 Net non-cash (credits) charges ......................................... (145) (1,137) Maintenance capital expenditures ....................................... (414) (1,125) ------ ------- Available Cash before reserves ......................................... $1,165 $ 7,063 ====== =======
Distributions for the three and nine month period total $1.4 million and $4.3 million, respectively. Available Cash (a non-GAAP liquidity measure) has been reconciled to cash flow from operating activities (the GAAP measure) for the three and nine months ended September 30, 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 us 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 we are 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 three and nine months ended September 30, 2005, is as follows: -31- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Nine Months Months Ended Ended September 30, September 30, 2005 2005 ------------- ------------- (in thousands) Cash flows from operating activities ............................... $ 5,098 $ 4,243 Adjustments to reconcile operating cash flows to Available Cash: Maintenance capital expenditures ................................ (414) (1,125) Proceeds from sales of certain assets ........................... 221 1,581 Amortization of credit facility issuance fees ................... (92) (279) Cash effects of stock appreciation rights plan .................. (9) (59) Effect of distributions from T&P Syngas ......................... 250 563 Net effect of changes in working capital accounts not included in calculation of Available Cash .................... (3,889) 2,139 ------- ------- Available Cash before reserves ..................................... $ 1,165 $ 7,063 ======= =======
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS In addition to our 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 September 30, 2005.
Payments Due by Period -------------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations 1 Year Years Years Years Total ---------------------------- --------- -------- ------ ------- -------- (in thousands) Long-term Debt ............. $ -- $ 32,600 $ -- $ -- $ 32,600 Operating Leases ........... 1,816 3,014 1,434 372 6,636 Interest Payments (1) ...... 2,567 4,241 -- -- 6,808 Unconditional Purchase Obligations (2) ......... 148,907 85,292 -- -- 234,199 -------- -------- ------ ---- -------- Total Contractual Cash Obligations ............. $153,290 $125,147 $1,434 $372 $280,243 ======== ======== ====== ==== ========
(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 September 30, 2005 remained outstanding through the maturity date of June 1, 2008 and interest rates remained at the September 30, 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 September 30, 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 ACCOUNTING PRONOUNCEMENTS For information on new accounting pronouncements see Note 2 to the consolidated financial statements. -32- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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; - 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 -33- GENESIS ENERGY, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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. -34- ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Price Risk Management and Financial Instruments 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 September 30, 2005, we had entered into NYMEX future contracts that will settle during October 2005. These contracts either do not qualify for hedge accounting or are fair value hedges, therefore the fair value of these 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.
Sell (Short) Contracts ------------ Futures Contracts Contract volumes (1,000 bbls) ........... 63 Weighted average price per bbl .......... $65.321 Contract value (in thousands) ........... $ 4,115 Mark-to-market change (in thousands) .... 58 ------- Market settlement value (in thousands) .. $ 4,173 =======
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 September 30, 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 September 30, 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 32,600 Average interest rate 7.36%
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 -35- 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 changes in our internal controls over financial reporting during the three months ended September 30, 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 12 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: November 9, 2005 By: /s/ ROSS A. BENAVIDES ------------------------------------ Ross A. Benavides Chief Financial Officer -36- Index to Exhibits 31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. 31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. 32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.