Edgar Filing: GENESIS ENERGY LP

form10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

o 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 (State or other jurisdictions of incorporation or organization)	76-0513049 (I.R.S. Employer Identification No.)

500 Dallas, Suite 2500, Houston, TX (Address of principal executive offices)	77002 (Zip code)

Registrant's telephone number, including area code:

(713) 860-2500

Securities registered pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Common Units outstanding as of May 9, 2008: 38,253,264

GENESIS ENERGY, L.P.

Form 10-Q

INDEX

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements	Page

	Unaudited Consolidated Balance Sheets - March 31, 2008 and December 31, 2007	3

	Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2008 and 2007	4

	Unaudited Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2008	5

	Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	6

	Notes to Unaudited Consolidated Financial Statements	7


Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

Item 4.	Controls and Procedures	40


PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 3.	Defaults upon Senior Securities	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	41

Item 6.	Exhibits	41


SIGNATURES		42

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS

(In thousands)

	March 31,			December 31,
	2008			2007

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,431		$	11,851
Accounts receivable - trade		195,998			178,658
Accounts receivable - related party		3,694			1,441
Inventories		17,915			15,988
Net investment in direct financing leases, net of unearned income - current portion - related party		594			609
Other		6,168			5,693
Total current assets		235,800			214,240

FIXED ASSETS, at cost		157,472			150,413
Less: Accumulated depreciation		(52,445	)		(48,413	)
Net fixed assets		105,027			102,000

NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related party		4,632			4,764
CO2 ASSETS, net of amortization		27,855			28,916
JOINT VENTURES AND OTHER INVESTMENTS		20,205			18,448
INTANGIBLE ASSETS, net of amortization		199,399			211,050
GOODWILL		319,918			320,708
OTHER ASSETS, net of amortization		10,197			8,397

TOTAL ASSETS	$	923,033		$	908,523

LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES
Accounts payable - trade	$	181,812		$	154,614
Accounts payable - related party		2,567			2,647
Accrued liabilities		14,266			17,537
Total current liabilities		198,645			174,798

LONG-TERM DEBT		82,000			80,000
DEFERRED TAX LIABILITIES		18,461			20,087
OTHER LONG-TERM LIABILITIES		1,279			1,264
MINORITY INTERESTS		569			570
COMMITMENTS AND CONTINGENCIES (Note 15)

PARTNERS' CAPITAL:
Common unitholders, 38,253 units issued and outstanding		605,974			615,265
General partner		16,105			16,539
Total partners' capital		622,079			631,804

TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	923,033		$	908,523

The accompanying notes are an integral part of these consolidated financial statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2008			2007
REVENUES:
Supply and logistics:
Unrelated parties	$	429,393		$	172,843
Related parties		725			436
Refinery services		43,912			-
Pipeline transportation, including natural gas sales:
Transportation services - unrelated parties		5,909			4,155
Transportation services - related parties		1,052			1,341
Natural gas sales revenues		1,324			1,292
CO2 marketing revenues:
Unrelated parties		3,163			2,867
Related parties		707			630
Total revenues		486,185			183,564
COSTS AND EXPENSES:
Supply and logistics costs:
Product costs - unrelated parties		407,275			167,711
Product costs - related parties		-			11
Operating costs		16,582			3,958
Refinery services operating costs		30,324			-
Pipeline transportation costs:
Pipeline transportation operating costs		2,356			2,685
Natural gas purchases		1,286			1,235
CO2 marketing costs:
Transportation costs - related party		1,257			1,098
Other costs		15			46
General and administrative		8,524			3,328
Depreciation and amortization		16,789			1,928
Net loss (gain) on disposal of surplus assets		18			(16	)
Total costs and expenses		484,426			181,984
OPERATING INCOME		1,759			1,580
Equity in earnings of joint ventures		178			261
Interest income		117			44
Interest expense		(1,786	)		(270	)
INCOME BEFORE INCOME TAXES		268			1,615
Income tax benefit (expense)		1,377			(30	)
NET INCOME	$	1,645		$	1,585

NET INCOME PER COMMON UNIT - BASIC AND DILUTED	$	0.04		$	0.11

WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
BASIC		38,253			13,784
DILUTED		38,297			13,784

The accompanying notes are an integral part of these consolidated financial statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(In thousands)

	Partners' Capital
	Number of
	Common		Common			General
	Units		Unitholders			Partner			Total

Partners' capital, January 1, 2008		38,253	$	615,265		$	16,539		$	631,804
Net income		-		1,612			33			1,645
Cash distributions		-		(10,903	)		(467	)		(11,370	)
Partners' capital, March 31, 2008		38,253	$	605,974		$	16,105		$	622,079

The accompanying notes are an integral part of these consolidated financial statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,645		$	1,585
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization		16,789			1,928
Amortization of credit facility issuance costs		268			136
Amortization of unearned income on direct financing leases		(148	)		(159	)
Payments received under direct financing leases		295			297
Equity in earnings of investments in joint ventures		(178	)		(261	)
Distributions from joint ventures - return on investment		517			424
Loss (gain) on disposal of assets		18			(16	)
Non-cash effects of unit-based compensation plans		(912	)		632
Deferred tax benefit		(1,626	)		-
Other non-cash items		(166	)		(245	)
Changes in components of operating assets and liabilities -
Accounts receivable		(21,194	)		1,102
Inventories		(1,928	)		(3,562	)
Other current assets		(371	)		808
Accounts payable		26,699			878
Accrued liabilities and taxes payable		(2,325	)		(1,810	)
Net cash provided by operating activities		17,383			1,737

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed assets		(6,439	)		(365	)
Distributions from joint ventures - return of investment		161			227
Investment in joint ventures and other investments		(2,210	)		-
Proceeds from disposal of assets		245			16
Other, net		(463	)		(90	)
Net cash used in investing activities		(8,706	)		(212	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		71,700			27,300
Bank repayments		(69,700	)		(25,100	)
Other, net		274			(169	)
Distributions to common unitholders		(10,903	)		(2,895	)
Distributions to general partner interest and minority interest owner		(468	)		(59	)
Net cash used in financing activities		(9,097	)		(923	)

Net (decrease) increase in cash and cash equivalents		(420	)		602
Cash and cash equivalents at beginning of period		11,851			2,318
Cash and cash equivalents at end of period	$	11,431		$	2,920

The accompanying notes are an integral part of these consolidated financial statements.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Organization

We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast area of the United States. We conduct our operations through our operating subsidiaries and joint ventures. We manage our businesses through four divisions:

Pipeline transportation of crude oil, and, to a lesser degree, natural gas and carbon dioxide (or CO2);

Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or NaHS, commonly pronounced nash);

Industrial gas activities, including wholesale marketing of CO2 and processing of syngas through a joint venture; and

Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting by trucks of crude oil and petroleum products as well as dry goods.

Our 2% general partner interest is held by Genesis Energy, Inc., a Delaware corporation and an indirect, wholly-owned subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. Our general partner also owns 7.4% of our outstanding common units.

Our general partner manages our operations and activities and employs our officers and personnel, who devote 100% of their efforts to our management.

Basis of Consolidation and Presentation

The accompanying unaudited consolidated financial statements and related notes present our consolidated financial position as of March 31, 2008 and December 31, 2007 and our results of operations for the three months ended March 31, 2008 and 2007, our cash flows for the three months ended March 31, 2008 and 2007 and changes in partners’ capital for the three months ended March 31, 2008. All intercompany transactions have been eliminated. The accompanying unaudited consolidated financial statements include Genesis Energy, L.P., its operating subsidiary, Genesis Crude Oil, L.P., and its subsidiaries. Our general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P., which is reflected in our financial statements as a minority interest.

In July 2007, we acquired the energy-related businesses of the Davison family. The results of the operations of these businesses have been included in our consolidated financial statements since August 1, 2007.

We own a 50% interest in T&P Syngas Supply Company and a 50% interest in Sandhill Group, LLC. These investments are accounted for by the equity method, as we exercise significant influence over their operating and financial policies. See Note 7.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The consolidated 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) that 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 when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Except per Unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2. Recent Accounting Developments

Implemented

SFAS 157

We adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157), with respect to financial assets and financial liabilities that are regularly adjusted to fair value, as of January 1, 2008. SFAS 157 provides a common fair value hierarchy to follow in determining fair value measurements in the preparation of financial statements and expands disclosure requirements relating to how such measurements were developed. SFAS 157 does not require any new fair value measurements, but rather applies to all other accounting pronouncements that require or permit fair value measurements. On February 12, 2008 the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2) which amends SFAS 157 to delay the effective date for all non-financial assets and non-financial liabilities, except for those that are recognized at fair value in the financial statements on a recurring basis. The partial adoption of SFAS 157 as described above had no material impact on us. We have not yet determined the impact, if any, that the second phase of the adoption of SFAS 157 in 2009 will have relating to its fair value measurements of non-financial assets and non-financial liabilities. See Note 17 for further information regarding fair-value measurements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159). This statement became effective for us as of January 1, 2008. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. We did not elect to utilize voluntary fair value measurements as permitted by the standard.

Pending

SFAS 141(R)

In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS 141(R)). SFAS 141(R) replaces FASB Statement No. 141, “Business Combinations.” This statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be charged to expense as incurred. In addition, the statement requires disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will adopt SFAS 141(R) on January 1, 2009 for acquisitions on or after that date.

SFAS 160

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This statement establishes accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior literature. A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company. This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of operations and, as a result, that net income be allocated between the parent and the noncontrolling interests on the face of the statement of operations; and (iii) enhanced disclosures regarding noncontrolling interests. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS 160 on January 1, 2009. We are assessing the impact of this statement on our financial statements and expect it to impact the presentation of the minority interest in our operating partnership.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SFAS 161

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures about our derivative and hedging activities. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 beginning January 1, 2009. We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.

EITF 07-4

In March 2008, the FASB ratified the consensus reached by the Emerging Issues Task Force (or EITF) of the FASB in issue EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” Under this consensus, the computation of earnings per unit will be affected by the incentive distribution rights (“IDRs”) we are contractually obligated to distribute at the end of the current reporting period. In periods when earnings are in excess of cash distributions, we will reduce net income or loss for the current reporting period by the amount of available cash that will be distributed to our limited partners and general partner for its general partner interest and incentive distribution rights for the reporting period, and the remainder will be allocated to the limited partner and general partner in accordance with their ownership interests. When cash distributions exceed current-period earnings, net income or loss will be reduced (or increased) by cash distributions, and the resulting excess of distributions over earnings will be allocated to the general partner and limited partner based on their respective sharing of losses. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We are currently evaluating the impact of EITF 07-4; however we expect it to have an impact on our presentation of earnings per unit beginning in 2009. For additional information on our incentive distribution rights, see Note 9.

3. Acquisitions

2007 Davison Businesses Acquisition

On July 25, 2007, we acquired five energy-related businesses from several entities owned and controlled by the Davison family of Ruston, Louisiana (the “Davison Acquisition”) for total consideration of $623 million (including cash and common units), net of cash acquired and direct transaction costs totaling $8.9 million. The businesses include the operations that comprise our refinery services division, and other operations included in our supply and logistics division, which transport, store, procure, and market petroleum products and other bulk commodities. The assets acquired in this transaction provide us with opportunities to expand our services to energy companies in the areas in which we operate.

The purchase price was allocated to the assets acquired and liabilities assumed based on estimated fair values. The purchase price allocation was adjusted during the first quarter of 2008 for differences in working capital and property and equipment acquired. These adjustments reduced the amount of the purchase price allocated to goodwill. See additional information on intangible assets and goodwill in Note 6.

2007 Port Hudson Assets Acquisition

Effective July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port Hudson crude oil truck terminal, marine terminal, and marine dock on the Mississippi River, which includes 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana. The purchase price was allocated to the assets acquired based on estimated fair values. See additional information on goodwill in Note 6.

4. Inventories

Inventories are valued at the lower of cost or market. The costs of inventories did not exceed market values at March 31, 2008 and December 31, 2007. The major components of inventories were as follows:

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

	March 31, 2008		December 31, 2007

Crude oil	$	4,475	$	3,710
Petroleum products		6,277		6,527
Caustic soda		3,432		1,998
NaHS		3,601		3,557
Other		130		196
Total inventories	$	17,915	$	15,988

5. Fixed Assets and Asset Retirement Obligations

Fixed assets consisted of the following:

	March 31, 2008			December 31, 2007

Land, buildings and improvements	$	12,417		$	11,978
Pipelines and related assets		64,268			63,169
Machinery and equipment		26,314			25,097
Transportation equipment		32,818			32,906
Office equipment, furniture and fixtures		3,313			2,759
Construction in progress		6,688			7,102
Other		11,654			7,402
Subtotal		157,472			150,413
Accumulated depreciation		(52,445	)		(48,413	)
Total	$	105,027		$	102,000

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with the removal of our oil, natural gas and CO2 pipelines, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. Accretion of the discount increases the liability and is recorded to expense.

The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2008.

Asset retirement obligations as of December 31, 2007	$	1,173
Accretion expense		18
Asset retirement obligations as of March 31, 2008	$	1,191

At March 31, 2008, $0.1 million of our asset retirement obligation was classified in “Accrued liabilities” under current liabilities in our Unaudited Consolidated Balance Sheets. Certain of our unconsolidated affiliates have asset retirement obligations recorded at March 31, 2008 and December 31, 2007 relating to contractual agreements. These amounts are immaterial to our financial statements.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

6. Intangible Assets and Goodwill

Intangible Assets

In connection with the Davison acquisition (See Note 3), we allocated a portion of the purchase price to intangible assets based on their fair values. The following table reflects the components of intangible assets being amortized at the dates indicated:

		March 31, 2008						December 31, 2007
	Weighted Amortization Period in Years	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value

Refinery services customer relationships	3	$	94,654	$	13,539	$	81,115	$	94,654	$	9,380	$	85,274
Supply and logistics customer relationships	5		34,630		4,992		29,638		34,630		3,287		31,343
Refinery services supplier relationships	2		36,469		13,079		23,390		36,469		9,241		27,228
Refinery services licensing agreements	6		38,678		3,458		35,220		38,678		2,218		36,460
Supply and logistics trade name	7		17,988		1,463		16,525		17,988		930		17,058
Supply and logistics favorable lease	15		13,260		316		12,944		13,260		197		13,063
Other	3		722		155		567		721		97		624
Total	5	$	236,401	$	37,002	$	199,399	$	236,400	$	25,350	$	211,050

The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services. The trade name is the Davison name, which we retained the right to use in our operations. The favorable lease relates to a lease of a terminal facility in Shreveport, Louisiana.

We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. The favorable lease and other intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $11.7 million for the three months ended March 31, 2008.

Estimated amortization expense for each of the five subsequent fiscal years is expected to be as follows:

	Amortization
	Expense to
Year Ended December 31	be Recorded
Remainder of 2008	$	34,715
2009	$	32,176
2010	$	25,575
2011	$	20,943
2012	$	17,511
2013	$	14,107

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Goodwill

In connection with the Davison and Port Hudson acquisitions, the residual of the purchase price over the fair values of the net tangible and identifiable intangible assets acquired was allocated to goodwill. The carrying amount of goodwill by business segment at March 31, 2008 was $296.8 million to refinery services and $23.1 million to supply and logistics.

7. Joint Ventures and Other Investments

T&P Syngas Supply Company

We own a 50% interest in T&P Syngas Supply Company (“T&P Syngas”), a Delaware general partnership. Praxair Hydrogen Supply Inc. (“Praxair”) owns the remaining 50% partnership interest in T&P Syngas. 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. We reflect in our Unaudited 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 Unaudited Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 included $0.3 million and $0.4 million, respectively, as our share of the operating earnings of T&P Syngas, reduced by amortization of the excess purchase price of $0.1 million in each period. We received distributions from T&P Syngas of $0.6 million for both the three months ended March 31, 2008 and 2007.

The tables below reflect summarized financial information for T&P Syngas:

	Three Months Ended			Three Months Ended
	March 31, 2008			March 31, 2007

Revenues	$	1,209		$	1,308
Operating expenses and depreciation		(367	)		(438	)
Other (expense) income		(7	)		5
Net income	$	835		$	875

	March 31, 2008		December 31, 2007

Current assets	$	2,628	$	2,562
Non-current assets		19,932		20,243
Total assets	$	22,560	$	22,805

Current liabilities	$	365	$	341
Non-current liabilities		185		180
Partners' capital		22,010		22,284
Total liabilities and partners' capital	$	22,560	$	22,805

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Sandhill Group, LLC

We own a 50% interest in Sandhill Group, LLC (“Sandhill”). At March 31, 2008, Reliant Processing Ltd. held the other 50% interest in Sandhill. Sandhill owns a CO2 processing facility located in Brandon, Mississippi. Sandhill is engaged in the production and distribution of liquid carbon dioxide for use in the food, beverage, chemical and oil industries. The facility acquires CO2 from us under a long-term supply contract that we acquired in 2005 from Denbury.

We are accounting for our 50% ownership in Sandhill under the equity method of accounting. We reflect in our Unaudited Consolidated Statements of Operations our equity in Sandhill’s net income, net of the amortization of the excess of our investment over our share of partners’ capital of Sandhill that is not considered goodwill.

Our Unaudited Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 included $36,000 and $9,000, respectively, as our share of the operating earnings of Sandhill, reduced by amortization of the excess purchase price of $69,000 in each period. We received distributions from Sandhill of $124,000 and $60,000 during the three months ended March 31, 2008 and 2007, respectively.

Other Projects

We have invested $4.5 million in the Faustina Project, a petroleum coke to ammonia project that is in the development stage. All of our investment may later be redeemed, with a return, or converted to equity after the project has obtained construction financing. The funds we have invested are being used for project development activities, which include the negotiation of off-take agreements for the products and by-products of the plant to be constructed, securing permits and securing financing for the construction phase of the plant. We have recorded our investment in this debt security at cost and classified it as held-to-maturity, since we have the intent and ability to hold it until it is redeemed.

No events or changes in circumstances have occurred that indicate a significant adverse effect on the fair value of our investment at March 31, 2008, therefore our investment is included in our Unaudited Consolidated Balance Sheet at cost.

8. Debt

Our credit facility, with a maximum facility amount of $500 million, of which $100 million can be used for letters of credit, is with a group of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc. The maximum facility amount represents the amount the banks have committed to fund pursuant to the terms of the credit agreement. The borrowing base is recalculated quarterly and at the time of material acquisitions. The borrowing base represents the amount that can be borrowed or utilized for letters of credit from a credit standpoint based on our EBITDA (earnings before interest, taxes, depreciation and amortization), computed in accordance with the provisions of our credit facility.

The borrowing base may be increased to the extent of pro forma additional EBITDA, (as defined in the credit agreement), attributable to acquisitions or internal growth projects with approval of the lenders. Our borrowing base as of March 31, 2008 was $361 million.

At March 31, 2008, we had $82 million borrowed under our credit facility and we had $7 million in letters of credit outstanding. 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 November 15, 2011. The total amount available for borrowings at March 31, 2008 was $272 million under our credit facility.

The key terms for rates under our credit facility are as follows:

The interest rate on borrowings may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 0.50% to the prime rate plus 1.875%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%. The rate is based on our leverage ratio as computed under the credit facility. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At March 31, 2008, our borrowing rates were the prime rate plus 1.25% or the LIBOR rate plus 2.25%. On April 1, 2008, the additional margin for prime rate borrowings and LIBOR rate borrowings declined to 0.50% and 1.50%, respectively.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Letter of credit fees will range from 1.50% to 2.875% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At March 31, 2008, our letter of credit rate was 2.25%. On April 1, 2008, this rate declined to 1.50%.

We pay a commitment fee on the unused portion of the $500 million maximum facility amount. The commitment fee will range from 0.30% to 0.50% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At March 31, 2008, the commitment fee rate was 0.50%. On April 1, 2008, this rate declined to 0.30%.

Collateral under the credit facility consists of substantially all our assets. While our general partner is jointly and severally liable for all of our obligations unless and except to the extent those obligations provide that they are non-recourse to our general partner, our credit facility expressly provides that it is non-recourse to our general partner (except to the extent of its pledge of its general partner interest in certain of our subsidiaries), as well as to Denbury and its other subsidiaries.

Our credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which we may conduct our business. Our credit facility contains three primary financial covenants - a debt service coverage ratio, leverage ratio and funded indebtedness to capitalization ratio – that require us to achieve specific minimum financial metrics. In general, our debt service coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense. Our leverage ratio calculation compares our consolidated funded debt (as calculated in accordance with our credit facility) to EBITDA (as adjusted). Our funded indebtedness ratio compares outstanding debt to the sum of our consolidated total funded debt plus our consolidated net worth.

		Required	Actual
		Ratio	Ratio as of
		through	March 31,
Financial Covenant	Requirement	June 30, 2008	2008

Debt Service Coverage Ratio	Minimum	2.75 to 1.0	4.1 to 1.0
Leverage Ratio	Maximum	6.0 to 1.0	1.2 to 1.0
Funded Indebtedness Ratio	Maximum	0.8 to 1.0	0.1 to 1.0

Our credit facility includes provisions for the temporary adjustment of the required ratios following material acquisitions and with lender approval. The ratios in the table above are the required ratios for the period following a material acquisition. If we meet these financial metrics and are not otherwise in default under our credit facility, we may make quarterly distributions; however, the amount of such distributions may not exceed the sum of the distributable cash generated by us for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. At March 31, 2008, the excess of distributable cash over distributions under this provision of the credit facility was $42.6 million.

The carrying value of our debt under our credit facility approximates fair value primarily because interest rates fluctuate with prevailing market rates, and the applicable margin on outstanding borrowings reflect what we believe is market.

9. Partners’ Capital and Distributions

Partners’ Capital

Partner’s capital at March 31, 2008 consists of 38,253,264 common units, including 2,829,055 units owned by our general partner, representing a 98% aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest), and a 2% general partner interest.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Our general partner owns all of our general partner interest, including incentive distribution rights, all of the 0.01% general partner interest in our operating partnership (which is reflected as a minority interest in the Unaudited Consolidated Balance Sheet at March 31, 2008) and operates our business.

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 by our partnership agreement) 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. As discussed in Note 8, our credit facility limits the amount of distributions we may pay in any quarter.

Pursuant to our partnership agreement, our general partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds, in addition to its 2% general partner interest. The allocations of distributions between our common unitholders and our general partner, including the incentive distribution rights is as follows:

				General
	Unitholders			Partner
Quarterly Cash Distribution per Common Unit:
Up to and including $0.25 per Unit		98.00	%		2.00	%
First Target - $0.251 per Unit up to and including $0.28 per Unit		84.74	%		15.26	%
Second Target - $0.281 per Unit up to and including $0.33 per Unit		74.26	%		25.74	%
Over Second Target - Cash distributions greater than $0.33 per Unit		49.02	%		50.98	%

We paid or will pay the following distributions in 2007 and 2008:

									General
				Limited			General		Partner
				Partner			Partner		Incentive
		Per Unit		Interests			Interest		Distribution		Total
Distribution For	Date Paid	Amount		Amount			Amount		Amount		Amount

Fourth quarter 2006	February 2007	$	0.210	$	2,895		$	59	$	-	$	2,954
First quarter 2007	May 2007	$	0.220	$	3,032		$	62	$	-	$	3,094
Second quarter 2007	August 2007	$	0.230	$	3,170	(1)	$	65	$	-	$	3,235	(1)
Third quarter 2007	November 2007	$	0.270	$	7,646		$	156	$	90	$	7,892
Fourth quarter 2007	February 2008	$	0.285	$	10,903		$	222	$	245	$	11,370
First quarter 2008	May 2008 (2)	$	0.300	$	11,476		$	234	$	429	$	12,139

(1) The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction. The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.

(2) This distribution will be paid on May 15, 2008 to the general partner and unitholders of record as of May 9, 2008.

Net (Loss) Income Per Common Unit

Subject to the applicability of Emerging Issues Task Force Issue No. 03-6 (“EITF 03-6”), Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128,” as discussed below, our net income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated 98% to the limited partners and 2% to the general partner. Basic net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period. Diluted net income per common unit is calculated in the same manner, but also considers the impact to common units for the potential dilution from phantom units outstanding.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In a period of net operating losses, incremental phantom units are excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

EITF 03-6 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders). EITF 03-06 applies to any accounting period where our aggregate net income exceeds our aggregate distribution. In such periods, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed from an economic or practical perspective. EITF 03-6 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner units. This result occurs as a larger portion of our aggregate earnings is allocated (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given period. Our aggregate net earnings have not exceeded our aggregate distributions; therefore EITF 03-6 has not had an impact on our calculation of earnings per unit. EITF 07-4, which will be effective for us beginning in 2009, will change the allocation of net income among our general partner and limited partners as described in Note 2.

The following table sets forth the computation of basic net income per common unit.

	Three Months Ended March 31,
	2008		2007
Numerators for basic and diluted net income per common unit:
Net income	$	1,645	$	1,585
Less general partner 2% ownership		33		32
Net income available for common unitholders	$	1,612	$	1,553

Denominator for basic per common unit:
Common Units		38,253		13,784

Denominator for diluted per common unit:
Common Units		38,253		13,784
Phantom Units		44		-
		38,297		13,784

Basic and diluted net income per common unit	$	0.04	$	0.11

10. Business Segment Information

Our operations consist of four operating segments: (1) Pipeline Transportation – interstate and intrastate crude oil, and to a lesser extent, natural gas and CO2 pipeline transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product; (3) Industrial Gases – the sale of CO2 acquired under volumetric production payments to industrial customers and our investment in a syngas processing facility, and (4) Supply and Logistics – terminaling, blending, storing, marketing, gathering, and transporting by truck crude oil and petroleum products and other dry goods. Our Supply and Logistics segment was previously known as Crude Oil Gathering and Marketing. With the Davison acquisition, we expanded our operations into petroleum products and other transportation services, and combined these operations due to their similarities and our approach to managing these operations. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures, including segment margin, segment volumes where relevant and maintenance capital investment. The tables below reflect our segment information as though the current segment designations had existed in all periods presented.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

We evaluate segment performance based on segment margin. We calculate segment margin as revenues less costs of sales and operating expenses, and we include income from investments in joint ventures. We do not deduct depreciation and amortization. All of our revenues are derived from, and all of our assets are located in, the United States. The pipeline transportation segment information includes the revenue, segment margin and assets of our direct financing leases.

	Pipeline		Refinery		Industrial		Supply &
	Transportation		Services		Gases (a)		Logistics		Total

Three Months Ended March 31, 2008
Segment margin excluding depreciation and amortization (b)	$	4,643	$	13,588	$	2,776	$	6,261	$	27,268

Capital expenditures	$	1,278	$	1,151	$	2,210	$	4,603	$	9,242
Maintenance capital expenditures	$	165	$	281	$	-	$	330	$	776
Net fixed and other long-term assets (c)	$	33,223	$	458,083	$	48,060	$	147,867	$	687,233

Revenues:
External customers	$	6,788	$	43,912	$	3,870	$	430,118	$	484,688
Intersegment (d)		1,497		-		-		-		1,497
Total revenues of reportable segments	$	8,285	$	43,912	$	3,870	$	430,118	$	486,185

Three Months Ended March 31, 2007
Segment margin excluding depreciation and amortization (b)	$	2,868		-	$	2,614	$	1,599	$	7,081

Capital expenditures	$	293		-	$	-	$	93	$	386
Maintenance capital expenditures	$	222		-	$	-	$	93	$	315
Net fixed and other long-term assets (c)	$	31,478		-	$	50,287	$	7,683	$	89,448

Revenues:
External customers	$	5,660		-	$	3,497	$	173,279	$	182,436
Intersegment (d)		1,128		-		-		-		1,128
Total revenues of reportable segments	$	6,788		-	$	3,497	$	173,279	$	183,564

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Industrial gases includes our CO2 marketing operations and our equity income from our investments in T&P Syngas and Sandhill.

Segment margin was calculated as revenues less cost of sales and operating expenses, excluding depreciation and amortization. It includes our share of the operating income of equity joint ventures. A reconciliation of segment margin to income before income taxes for the periods presented is as follows:

	Three Months Ended March 31,
	2008			2007

Segment margin excluding depreciation and amortization	$	27,268		$	7,081
General and administrative expenses		(8,524	)		(3,328	)
Depreciation and amortization expense		(16,789	)		(1,928	)

Net (loss) gain on disposal of surplus assets		(18	)		16
Interest expense, net		(1,669	)		(226	)
Income before income taxes	$	268		$	1,615

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.

Intersegment sales were conducted on an arm’s length basis.

11. 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. The transactions with related parties were as follows:

	Three Months Ended March 31,
	2008		2007

Truck transportation services provided to Denbury	$	458	$	436
Pipeline transportation services provided to Denbury	$	1,295	$	1,224
Payments received under direct financing leases from Denbury	$	295	$	297
Pipeline transportation income portion of direct financing lease fees with Denbury	$	162	$	158
Pipeline monitoring services provided to Denbury	$	30	$	30
Directors' fees paid to Denbury	$	30	$	30
CO2 transportation services provided by Denbury	$	1,257	$	1,128
Crude oil purchases from Denbury	$	-	$	11
Operations, general and administrative services provided by our general partner	$	14,328	$	6,071
Distributions to our general partner on its limited partner units and general partner interest	$	1,274	$	273
Sales of CO2 to Sandhill	$	707	$	630
Petroleum products sales to Davison family businesses	$	266	$	-

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Transportation Services

We provide truck transportation services to Denbury to move their crude oil from the wellhead to our Mississippi pipeline. Denbury pays us a fee for this trucking service that varies with the distance the crude oil is trucked. These fees are reflected in the statement of operations as supply and logistics revenues.

Denbury is the only shipper on our Mississippi pipeline other than us, and we earn tariffs for transporting their oil. 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.

We also provide pipeline monitoring services to Denbury. This revenue is included in pipeline revenues in the unaudited statements of operations.

Directors’ Fees

We paid Denbury for the services of each of four of Denbury’s officers who serve as directors of our general partner, at an annual rate that is $10,000 per person less than the rate at which our independent directors were paid.

CO2 Operations and Transportation

Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver CO2 for us to our customers. In the first three months of 2008, the inflation-adjusted transportation fee averaged $0.1895 per Mcf.

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 March 31, 2008 and December 31, 2007, we owed Denbury $1.0 million, respectively, for purchases of crude oil and CO2 transportation charges. Denbury owed us $0.9 million for transportation services at March 31, 2008 and December 31, 2007, respectively. We owed our general partner $1.5 million and $0.7 million for administrative services at March 31, 2008 and December 31, 2007, respectively. At March 31, 2008 and December 31, 2007, Sandhill owed us $0.7 and $0.5 million for purchases of CO2, respectively. At December 31, 2007, we owed the Davison family entities $0.8 million for reimbursement of costs paid primarily related to employee transition 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. Our credit agreement obligations are not guaranteed by Denbury or any of its other subsidiaries. Our credit facility is non-recourse to our general partner, except to the extent of its pledge of its 0.01% general partner interest in our operating partnership.

We guarantee 50% of the obligation of Sandhill to a bank. At March 31, 2008, the total amount of Sandhill’s obligation to the bank was $3.6 million; therefore, our guarantee was for $1.8 million.

12. Major Customers and Credit Risk

Due to the nature of our supply and logistics operations, a disproportionate percentage of our trade receivables consists of 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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.

Shell Oil Company accounted for 18% of total revenues in the first quarter of 2008. Shell Oil Company, Occidental Energy Marketing, Inc., and Calumet Specialty Products Partners, L.P. accounted for 23%, 20% and 12% of total revenues in the first quarter of 2007, respectively. The majority of the revenues from these customers in both periods relate to our crude oil supply and logistics operations.

13. Supplemental Cash Flow Information

Cash received by us for interest for the three months ended March 31, 2008 and 2007 was $78,000 and $27,000, respectively. Payments of interest and commitment fees were $2,398,000 and $20,000 for the three months ended March 31, 2008 and 2007, respectively.

Cash paid for income taxes during the three months ended March 31, 2008 was $62,000.

At March 31, 2008, we had incurred liabilities for fixed asset and other asset additions totaling $1.3 million that had not been paid at the end of the first quarter, and, therefore, are not included in the caption “Payments to acquire fixed assets” and “Other, net” under investing activities on the Unaudited Consolidated Statements of Cash Flows.

14. Derivatives

Our market risk in the purchase and sale of crude oil and petroleum products 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, fuel oil and petroleum products 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, “Accounting for Derivative Instruments and Hedging Activities.” At March 31, 2008, we had futures contracts 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 March 31, 2008. We marked these contracts to fair value at March 31, 2008. During the three months ended March 31, 2008, we recorded losses of $1.0 million related to derivative transactions, which are included in the Unaudited Consolidated Statements of Operations under the caption “Supply and logistics costs.” We did not utilize any derivatives that were accounted for as hedges during the three months ended March 31, 2008.

The consolidated balance sheet at March 31, 2008 includes a decrease in other current assets of $0.3 million as a result of these derivative transactions. The consolidated balance sheet at December 31, 2007 included a decrease in other current assets of $0.7 million as a result of derivative transactions.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED 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 March 31, 2008 and December 31, 2007.

15. Contingencies

Guarantees

We guaranteed $1.2 million of residual value related to the leases of trailers from a lessor. We believe the likelihood that we would be required to perform or otherwise incur any significant losses associated with this guarantee is remote.

We guaranteed 50% of the obligations of Sandhill under a credit facility with a bank. At March 31, 2008, Sandhill owed $3.6 million; therefore our guaranty was $1.8 million. Sandhill makes principal payments for this obligation totaling $0.6 million per year.

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, or 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 third party claims against us 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 (“Howell”) entered into a sublease with Koch Industries, Inc. (“Koch”), 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. In 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.

We were formed in 1996 by the sale and contribution of assets from Howell and Basis Petroleum, Inc. (“Basis”). 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 intend to seek recovery of Basis' share of potential liabilities and defense costs with respect to Jay Station.

We have developed a plan of remediation for affected soil and groundwater at Jay Station which has been approved by appropriate state regulatory agencies. We have accrued an estimate of our share of liability for this matter in the amount of $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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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.

In connection with the sale of pipeline assets in Texas in the fourth quarter of 2003, we retained responsibility for environmental matters related to the operations of those pipelines in the periods prior to the date of the sales, subject to certain conditions. On the majority of the pipelines sold, our responsibility for any environmental claim will not exceed an aggregate total of $2 million. Our responsibility for indemnification related to these sales will cease in 2013.

Other Matters

Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. 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.

16. Unit-Based Compensation Plans

Stock Appreciation Rights Plan

The adjustment of the liability for our stock appreciation rights plan to its fair value at March 31, 2008 resulted in a credit to expense for the three months ended March 31, 2008 of $0.9 million, with $0.6 million, $0.2 million and $0.1 million included in general and administrative expenses, pipeline operating costs, and supply and logistics operating costs, respectively. An immaterial amount of expense was recorded to refinery services operating costs related to grants awarded in the first quarter of 2008. The decrease in our common unit market price from December 31, 2007 to March 31, 2008 of $4.66 reduced the accrual for the plan, providing a credit to the expense we recorded under our plan during the three months ended March 31, 2008. The adjustment of the liability to its fair value at March 31, 2007, resulted in expense for the three months ended March 31, 2007 of $0.6 million, with $0.3 million, $0.2 million and $0.1 million included in general and administrative expenses, supply and logistics operating costs, and pipeline operating costs, respectively.

The following table reflects rights activity under our plan during the three months ended March 31, 2008:

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Stock Appreciation Rights	Rights			Weighted Average Exercise Price		Weighted Average Contractual Remaining Term (Yrs)		Aggregate Intrinsic Value

Outstanding at January 1, 2008		593,458		$	15.45
Granted		508,228		$	20.90
Exercised		(10,958	)	$	21.71
Forfeited or expired		(18,699	)	$	18.49
Outstanding at March 31, 2008		1,072,029		$	18.04		8.7	$	2,822
Exercisable at March 31, 2008		315,264		$	14.06		7.1	$	1,781

The weighted-average fair value at March 31, 2008 of rights granted during the first quarter of 2008 was $3.02 per right, determined using the following assumptions:

Assumptions for Computation of Fair Value of Rights Granted in First Quarter 2008
Expected life of rights (in years)	6.25 - 7.00
Risk-free interest rate	2.76% - 2.93%
Expected unit price volatility	33.99%
Expected future distribution yield	6.00%

The total intrinsic value of rights exercised during the first quarter of 2008 was $0.1 million, which was paid in cash to the participants.

At March 31, 2008, there was $1.7 million of total unrecognized compensation cost related to rights that we expect will vest under the plan. This amount was calculated as the fair value at March 31, 2008 multiplied by those rights for which compensation cost has not been recognized, adjusted for estimated forfeitures. This unrecognized cost will be recalculated at each balance sheet until the rights are exercised, forfeited, or expire. For the awards outstanding at March 31, 2008, the remaining cost will be recognized over a weighted average period of 0.7 years.

2007 Long Term Incentive Plan

Subject to adjustment as provided in the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may be granted under the 2007 LTIP, of which 951,472 remain authorized for issuance at March 31, 2008. In February 2008, 9,166 Phantom Units were granted with vesting at the end of three years. The aggregate grant date fair value of these Phantom Unit awards was $0.2 million based on the grant date market price of our common units of $17.89 per unit, adjusted for distributions that holders of phantom units will not receive during the vesting period.

As of March 31, 2008, there was $0.9 million of unrecognized compensation expense related to these units. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.7 years.

The following table summarizes information regarding our non-vested Phantom Unit grants as of March 31, 2008:

			Weighted Average
	Number of		Grant-Date
Non-vested Phantom Unit Grants	Units		Fair Value

Non-vested at January 1, 2008		39,362	$	21.92
Granted		9,166	$	17.89
Non-vested at March 31, 2008		48,528	$	21.16

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

17. Fair-Value Measurements

As discussed in Note 2, we partially adopted SFAS 157 effective January 1, 2008 which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. SFAS 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy requires entities to maximize the use of observable inputs and minimize the use of unobservable inputs. The three levels of inputs used to measure fair value are as follows:

Level 1:

Quoted prices in active markets for identical, unrestricted assets or liabilities.

Level 2:

Observable market-based inputs or unobservable inputs that are corroborated by market data.

Level 3:

Unobservable inputs that are not corroborated by market data, which require us to develop our own assumptions. These inputs include certain pricing models, discounted cash flow methodologies and similar techniques that use significant unobservable inputs.

Our derivative contracts are exchange-traded futures and exchange-traded option contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1. See Note 14 for additional information on our derivative instruments.

We generally apply fair value techniques on a non-recurring basis associated with (1) valuing the potential impairment loss related to goodwill pursuant to SFAS 142, and (2) valuing potential impairment loss related to long-lived assets accounted for pursuant to SFAS 144.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

	Carrying Amount			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)



Crude oil and petroleum products derivative instruments (based on quoted market prices on NYMEX)	$	(1,038	)	$	(1,038	)	$	-	$	-

18. Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Our taxable income or loss is includible in the federal income tax returns of each of our partners.

A portion of the operations we acquired in the Davison transaction are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay federal and state income taxes on these operations. The income taxes associated with these operations are accounted for in accordance with SFAS 109 “Accounting for Income Taxes.”

In May 2006, the State of Texas enacted a law which will require us to pay a tax of 0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The “margin” to which the tax rate will be applied generally will be calculated as our revenues (for federal income tax purposes) less the cost of the products sold (for federal income tax purposes), in the State of Texas.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2008, we have provided current tax expense in the amount of $0.2 million as the estimate of the taxes that will be owed on our income for the period, and a deferred tax benefit of $1.6 million related to temporary differences, related primarily to differences between amortization of intangible assets for financial reporting and tax purposes. We recorded a decrease of $0.5 million in the liability for uncertain tax benefits during the three months ended March 31, 2008. This decrease was attributable to uncertain tax positions associated with deferred tax liabilities and goodwill.

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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

Pending Drop-down Transactions

Liquidity and Capital Resources

Commitments and Off-Balance Sheet Arrangements

Results of Operations

New Accounting Pronouncements

In the discussions that follow, we will focus on two measures that we use to manage our 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 revenues less cost of sales and operating expenses (excluding depreciation and amortization) plus our equity in the operating income of joint ventures. A reconciliation of segment margin to income from continuing operations is included in our segment disclosures in Note 10 to the consolidated financial statements.

Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, 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 substitution of cash generated by our joint ventures in lieu of our equity income attributable to our joint ventures, and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows. 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

The first quarter of 2008 was the second full quarter that included the operations acquired from the Davison family in July 2007. The increases in Available Cash before Reserves resulting from this acquisition enabled us to announce our eleventh consecutive increase in our quarterly distribution. On April 28, 2008, we announced that our distribution to our common unitholders relative to the first quarter of 2008 will be $0.30 per unit (to be paid in May 2008), which is an increase of 5% relative to the distribution for the fourth quarter of 2007. This distribution amount represents a 36% increase from our distribution of $0.22 per unit for the first quarter of 2007. During the first quarter of 2008, we paid a distribution of $0.285 per unit related to the fourth quarter of 2007.

During the first quarter of 2008, we generated $15.8 million of Available Cash before Reserves, and we will distribute $12.1 million to holders of our common units and general partner for the first quarter. During the first quarter of 2008, cash provided by operating activities was $17.4 million.

In the first quarter of 2008, we reported net income of $1.6 million, or $0.04 per common unit, with $0.9 million of that income attributable to a reduction in the accrual we recorded for our stock appreciation rights plan. The decrease in our common unit market price from December 31, 2007 to March 31, 2008 of $4.66 reduced the accrual for the plan, providing a credit to the expense we recorded under our plan during the three months ended March 31, 2008. Non-cash depreciation and amortization totaling $16.8 million reduced net income during the first quarter.

Pending Drop-down Transactions

As a result of our acquisition from the Davisons, Denbury will enter into “drop-down” transactions with us involving two of their existing CO2 pipelines - the NEJD and Free State CO2 pipelines. We expect to pay for these pipeline assets with $225 million in cash and $25 million of our common units based on the average closing price of our units for the five trading days surrounding the closing of the transaction. We expect to receive approximately $30 million per annum, in the aggregate, under the lease and the transportation services agreement (and a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State pipeline are dependent on the volumes of CO2 transported therein. The business terms of the transactions have been completed and the associated documentation, requisite approvals and closing should be completed in the near future.

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Liquidity and Capital Resources

Capital Resources/Sources of Cash

In the last two years, we have adopted a growth strategy that has dramatically increased our cash requirements. We now expect our capital resources to include equity and debt offerings (public and private) and other financing transactions. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs. Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, to utilize our current credit facility and to implement our growth strategy successfully. While we anticipate that we will fund our distributions and our internal growth and maintenance capital expenditures, as well as the drop-downs from Denbury with borrowings under our existing credit facility, we will need to access the debt or equity markets to make any significant acquisitions. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms. Current market conditions may make the terms of cost of credit or equity cost prohibitive in relation to the economics of an acquisition. If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.

In November 2006, we entered into a credit facility with a maximum facility amount of $500 million. A maximum of $100 million may be used for letters of credit. The borrowing base under the facility at March 31, 2008 was approximately $361 million, and is recalculated quarterly and at the time of acquisitions. The borrowing base represents the amount that can be borrowed or utilized for letters of credit based on our EBITDA, computed in accordance with the provisions of our credit facility.

The terms of our credit facility also effectively limit the amount of distributions that we may pay to our general partner and holders of common units. Such distributions may not exceed the sum of the distributable cash generated for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. See Note 8 of the Notes to the Unaudited Consolidated Financial Statements.

Uses of Cash

Our cash requirements include funding day-to-day operations, maintenance and expansion capital projects, debt service, refinancings, and distributions on our common units and other equity interests. We expect to use cash flows from operating activities to fund cash distributions and maintenance capital expenditures needed to sustain existing operations. Future expansion capital – acquisitions or capital projects – will require funding through various financing arrangements, as more particularly described under “Liquidity and Capital Resources – Capital Resources/Sources of Cash” above.

Operating. Our operating cash flows are affected significantly by changes in items of working capital. The timing of capital expenditures and the related effect on our recorded liabilities affects operating cash flows.

The majority of the accounts receivable reflected on our consolidated balance sheets relate to our crude oil operations. These 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. Accounts receivable in our fuel procurement business also settle within 30 days of delivery. Over 80% of the $199.7 million aggregate receivables on our consolidated balance sheet at March 31, 2008 relate to our crude oil and fuel procurement businesses.

Investing. We utilized some of our cash flow for capital expenditures. We paid $6.4 million for capital expenditures and received $0.2 million from the sale of surplus assets. We received distributions of $0.2 million from our T&P Syngas joint venture that exceeded our share of the earnings of T&P Syngas during the first quarter of 2008.

Financing. Net cash of $9.1 million was utilized in financing activities. Our net borrowings under our credit facility were $2.0 million. We paid distributions totaling $11.4 million to our limited partners and our general partner during the quarter, and received $0.3 million from other financing activities.

Capital Expenditures. A summary of our capital expenditures, in the three months ended March 31, 2008 and 2007 is as follows:

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	Three Months Ended March 31,
	2008		2007
	(in thousands)
Capital expenditures for property, plant and equipment:
Maintenance capital expenditures:
Pipeline transportation assets		165		222
Supply and logistics assets		304		91
Refinery services assets		281		-
Administrative and other assets		26		2
Total maintenance capital expenditures		776		315

Growth capital expenditures:
Pipeline transportation assets		1,113		71
Supply and logistics assets		4,273		-
Refinery services assets		870		-
Total growth capital expenditures		6,256		71
Total		7,032		386

Capital expenditures attributable to unconsolidated affiliates:
Faustina project		2,210		-
Total		2,210		-
Total capital expenditures	$	9,242	$	386

During 2008, we expect to expend approximately $6.1 million for maintenance capital projects in progress or planned. Those expenditures are expected to include approximately $3.3 million of improvements in our refinery services business, $0.6 million in our crude oil pipeline operations, $1.5 million related to the relocation of our headquarters office when our existing lease ends in October 2008 and the remainder on projects related to our truck transportation and information technology areas. Most of our truck fleet is less than two years old, so we do not anticipate making any significant expenditures for vehicles in 2008; however, in future years we expect to spend $4 million to $5 million per year on vehicle replacements. Based on the information available to us at this time, we do not anticipate that future capital expenditures for compliance with regulatory requirements will be material.

We have started construction of an expansion of our existing Jay System that will extend the pipeline to producers operating in southern Alabama. That expansion will consist of approximately 33 miles of pipeline and gathering connections to approximately 35 wells and will include storage capacity of 20,000 barrels. We expect to spend a total of approximately $9.9 million on this project in 2008. Our refinery services segment expects to expend approximately $7.5 million on projects currently in progress to expand its operations in 2008 to two additional refineries. We also increased our base level of crude oil inventory by $4.3 million related to our Port Hudson facility, which is included in fixed assets. This is the level of inventory needed to ensure efficient and uninterrupted operations of the facility.

As discussed above in “Pending Drop-down Transactions”, we are currently in the process of finalizing drop-down transactions with Denbury related to two of its CO2 pipelines.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in “Capital Resources -- Sources of Cash.” We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. The arrangement that Denbury has made with our senior executive management team provides incentives to them to make such acquisitions.

Distributions

We are required by our partnership agreement to distribute 100% of our available cash (as defined therein) 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. We have increased our distribution for each of the last six quarters, including the distribution to be paid for the first quarter of 2008, as shown in the table below (in thousands, except per unit amounts).

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									General
				Limited			General		Partner
				Partner			Partner		Incentive
		Per Unit		Interests			Interest		Distribution		Total
Distribution For	Date Paid	Amount		Amount			Amount		Amount		Amount

Fourth quarter 2006	February 2007	$	0.210	$	2,895		$	59	$	-	$	2,954
First quarter 2007	May 2007	$	0.220	$	3,032		$	62	$	-	$	3,094
Second quarter 2007	August 2007	$	0.230	$	3,170	(1)	$	65	$	-	$	3,235	(1)
Third quarter 2007	November 2007	$	0.270	$	7,646		$	156	$	90	$	7,892
Fourth quarter 2007	February 2008	$	0.285	$	10,903		$	222	$	245	$	11,370
First quarter 2008	May 2008 (2)	$	0.300	$	11,476		$	234	$	429	$	12,139

(2) This distribution will be paid on May 15, 2008 to the general partner and unitholders of record as of May 9, 2008.

See Notes 8 and 9 of the Notes to the Unaudited Consolidated Financial Statements.

Available Cash before Reserves for the three months ended March 31, 2008 is as follows (in thousands):

	Three Months
	Ended
	3/31/2008
Net income	$	1,645
Depreciation and amortization		16,789
Cash received from direct financing leases not included in income		147
Cash effects of sales of certain assets		245
Effects of available cash generated by investments in joint ventures not included in income		423
Cash effects of stock appreciation rights plan		(158	)
Other non-cash credits		(2,528	)
Maintenance capital expenditures		(776	)
Available Cash before Reserves	$	15,787

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2008 below. For the three months ended March 31, 2008, cash flows provided by operating activities were $17.4 million.

Non-GAAP Financial Measure

This quarterly report includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP. The accompanying schedule provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts, and other market participants.

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Available Cash before Reserves, also referred to as discretionary cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.

Available Cash before Reserves is a liquidity measure used by our management to compare cash flows generated by us to the cash distribution paid to our limited partners and 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 aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2008, is as follows (in thousands):

	Three Months
	Ended
	March 31,2008
Cash flows from operating activities	$	17,383
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures		(776	)
Proceeds from sales of certain assets		245
Amortization of credit facility issuance fees		(268	)
Effects of available cash generated by investments in joint ventures not included in cash flows from operating activities		84
Net effect of changes in operating accounts not included in calculation of Available Cash		(881	)
Available Cash before Reserves	$	15,787

Commitments and Off-Balance-Sheet Arrangements

Contractual Obligations and Commercial Commitments

Our obligations that are not currently recorded on our balance sheet consist of our operating leases and crude oil purchase commitments. Neither the amounts nor the terms of these commitments or contingent obligations have changed significantly from the year-end 2007 amounts reflected in our Annual Report on Form 10-K. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Commitments and Off-Balance Sheet Arrangements” contained in our 2007 Annual Report on Form 10-K for further information regarding our commitments and obligations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” above, nor do we have any debt or equity triggers based upon our unit or commodity prices.

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Results of Operations

The contribution of each of our segments to total segment margin in the first quarters of 2008 and 2007 was as follows:

	Three Months Ended March 31,
	2008		2007
	(in thousands)
Pipeline transportation	$	4,643	$	2,868
Refinery services		13,588		-
Industrial gases		2,776		2,614
Supply and logistics		6,261		1,599
Total segment margin	$	27,268	$	7,081

Pipeline Transportation Segment

We operate three crude oil common carrier pipeline systems in a four-state area. We refer to these pipelines as our Mississippi System, Jay System, and Texas System. Additionally, we operate a CO2 pipeline in Mississippi to transport CO2 from Denbury’s main CO2 pipeline to Brookhaven oil field. Denbury has the exclusive right to use this CO2 pipeline. We also have several small natural gas gathering systems.

Denbury is the largest producer (based on average barrels produced per day) of crude oil in the State of Mississippi. Our Mississippi System is adjacent to several of Denbury’s existing and prospective oil fields. As Denbury continues to acquire and develop old oil fields using CO2 based tertiary recovery operations, we expect Denbury to add crude oil gathering and CO2 supply infrastructure to those fields, which could create opportunities for us.

The Jay System in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Recent changes in the ownership of the more mature producing fields in the area surrounding our Jay System have led to interest in further development or re-development of these fields which may lead to increases in production. Additionally, new wells have been drilled in the area. This new production produces greater tariff revenue for us due to the greater distance that the crude oil is transported on the pipeline. In August 2007, we announced that we will construct an expansion of our existing Jay System that will extend to producers operating in southern Alabama. This extension will consist of approximately 33 miles of pipeline and gathering connections to approximately 35 wells and storage capacity of 20,000 barrels. We expect to place these facilities in service in the first quarter of 2009. The production from these wells is currently being transported to our existing Jay System by our trucks. This expansion will allow us to re-deploy the trucks to other operations.

Our Texas System is dependent on connecting carriers for supply, and on two refineries for demand for our services. Volumes on the Texas System fluctuate as a result of changes in the supply available for the two refineries to acquire and ship on our pipeline. 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.

Operating results for our pipeline transportation segment were as follows:

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	Three Months Ended March 31,
	2008			2007
	(in thousands)
Crude oil tariffs and revenues from direct financing leases of crude oil pipelines	$	4,126		$	3,536
Sales of crude oil pipeline loss allowance volumes		2,459			1,699

Revenues from direct financing leases of CO2 pipelines		78			82
Tank rental reimbursements and other miscellaneous revenues		267			163
Total revenues from crude oil and CO2 tariffs, including revenues from direct financing leases		6,930			5,480
Revenues from natural gas tariffs and sales		1,355			1,308
Natural gas purchases		(1,286	)		(1,235	)
Pipeline operating costs		(2,356	)		(2,685	)
Segment margin	$	4,643		$	2,868

Barrels per day on crude oil pipelines:
Total		66,032			57,874
Mississippi System		22,854			19,355
Jay System		14,616			12,812
Texas System		28,562			25,707

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

Pipeline segment margin for the first quarter of 2008 increased $1.8 million as compared to the first quarter of 2007. Revenues from crude oil tariffs and related sources and sales of pipeline loss allowance volumes increased a total of $1.5 million. Pipeline operating costs decreased $0.3 million between the two periods, and the contribution to segment margin from natural gas activities was consistent.

Crude oil tariff and direct financing lease revenues increased $0.6 million primarily due to volume increases on all of our pipeline systems totaling 8,158 barrels per day. The tariff on the Mississippi System is an incentive tariff, such that the average tariff per barrel decreases as the volumes increase, however the overall impact of an annual tariff increase on July 1, 2007 with the volume increase still resulted in improved revenues from this system by $0.2 million. As a result of the annual tariff increase on July 1, 2007, average tariffs on the Jay System increased by approximately $0.03 per barrel between the two periods, which, when combined with the 1,804 barrels per day increase in volumes, improved tariff revenues from this system by $0.2 million. The volume increase is due in part to the renewed interest by oil producers in the fields in the area and additional volumes we are bringing to the system from other locations. Volumes on the Texas System increased by 2,855 barrels per day, although the impact on revenues was not very significant due to the relatively low tariffs on that system. Approximately 78% of the volume on that system is shipped on a tariff of $0.31 per barrel.

Higher market prices for crude oil added $0.8 million to pipeline loss allowance revenues. Crude oil market prices have increased approximately $40 per barrel between the two quarters.

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 power cost increases. We perform regular maintenance on our assets in an effort to keep them in good operational condition and to minimize cost increases. Operations and maintenance costs, excluding the effects of our stock appreciation rights plan were flat when compared to the prior period. A decrease in the costs related to our stock appreciation right plan expense that relates to our pipeline operations personnel resulted in the decline in pipeline operating costs between the quarters.

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Refinery Services Segment

We acquired our refinery services segment in the Davison transaction in July 2007. That segment provides services to eight refining operations primarily located in Texas, Louisiana, and Arkansas. In our processing, we apply proprietary technology that uses large quantities of caustic soda (the primary input used by our proprietary process). Our refinery services business generates revenue by providing a service for which it receives 100% of the NaHS as compensation and by selling the NaHS, the by-product of our process, to approximately 100 customers. Some of the largest customers for the NaHS are copper mining companies in the United States and South America and paper mills.

The largest cost component of providing the service is acquiring and delivering caustic soda to our operations. Caustic soda, or NaOH, is the scrubbing agent introduced in the sour gas stream to remove the sulfur and generate the by-product, NaHS. Therefore the contribution to segment margin involves the revenues generated from the sales of NaHS less our total cost of providing the services, including the costs of acquiring and delivering caustic soda to our service locations. We estimate that approximately 65% of our NaHS sales are indexed, in one form or another, to our cost of caustic soda. Because the activities of these service arrangements can fluctuate, we do, from time to time, engage in other activities such as selling caustic soda, buying NaHS from other producers for re-sale to our customers and buying and selling sulfur, the financial results of which are also reported in our refinery services segment.

Segment margin from our refinery services for the first quarter of 2008 was $13.6 million. On a pro forma basis, refinery services segment margin would have been $12.8 million for the first quarter of 2007.

We believe the most meaningful measure of our success in this segment is the revenue generated from sales of NaHS after deducting delivery expenses, from both the volumes received as payment for rendering service as well as volumes obtained from third party producers.

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2008		2007

NaHS Sales
Dry Short Tons (DST)		41,742		38,781
Net Sales per DST	$	660	$	560
Contribution Margin per DST	$	260	$	260

During the first quarter of 2008, sales of NaHS, measured in dry short tons (DST) were 41,742 DST, or an average of 458 DST per day. The average sales price of the NaHS, net of delivery expenses, for the period was $660 per DST. Comparing the historical results of the predecessor for the first quarter of 2007 with our results for the first quarter of 2008 indicates that the average sales price per DST of NaHS, net of delivery expenses, increased between the two periods by 18%. The total difference in DST sold between the periods was 2,961 DST more in the first quarter of 2008 than the same period in 2007. As we expand our sour gas processing services to additional refineries, we expect these NaHS sales volumes to continue to increase. The increased worldwide demand for copper has contributed to the increased demand for NaHS.

The largest input to processing of the sour gas streams that result in NaHS is caustic soda. We also market caustic soda and sulfidic caustic not used for our processing. During the first quarter of 2008, the average market price for caustic soda was $476 per DST, an increase of 41% over the market price in the first quarter of 2007. We have generally been successful in increasing the sales price of NaHS to compensate for increases in caustic soda prices and maintaining or expanding the contribution of NaHS sales to our segment margin.

Industrial Gases Segment

Our industrial gases segment includes the results of our CO2 sales to industrial customers and our share of the operating income of our 50% joint venture interests in T&P Syngas and Sandhill.

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CO2 - Industrial Customers - We supply CO2 to industrial customers under seven long-term CO2 sales contracts. The sales contracts contain provisions for adjustments for inflation to sales prices based on the Producer Price Index, with a minimum price.

Our 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 historical data for 2004 through the first quarter of 2008, 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. Volumes sold each quarter in 2007 and in the first quarter of 2008 were as follows:

	Sales
	Mcf per Day

First Quarter 2007		67,158
Second Quarter 2007		75,039
Third Quarter 2007		85,705
Fourth Quarter 2007		80,667
First Quarter 2008		73,062

Operating Results - Operating results from our industrial gases segment were as follows:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Revenues from CO2 sales	$	3,870		$	3,497
CO2 transportation and other costs		(1,272	)		(1,144	)
Equity in earnings of joint ventures		178			261
Segment margin	$	2,776		$	2,614

Volumes per day:
CO2 sales - Mcf		73,062			67,158

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

The increase in margin from the industrial gases between the two periods was the result of an increase in CO2 sales volumes of 8.8%. Variations in the volumes sold among contracts with different pricing terms resulted in the average sales price of the CO2 remaining consistent between the periods despite inflation adjustment factors in the sales contracts.

The increased volumes and the inflation adjustment to the rate we pay Denbury to transport the CO2 in its pipeline to our customers resulted in greater CO2 transportation costs in the first quarter of 2008 when compared to the 2007 quarter. The transportation rate increase between the two quarters was 5.6%.

Our share of the operating income of T&P Syngas for the three months ended March 31, 2008 and 2007 was $0.3 million and $0.4 million, respectively. We reduced the amount we recorded as our equity in T&P Syngas by $0.1 million in each period as amortization of the excess purchase price of T&P Syngas. During the first quarters of 2008 and 2007, T&P Syngas paid us distributions totaling $0.6 million, attributable to the fourth quarters of the prior years.

Our share of the operating income of Sandhill for the first quarters of 2008 and 2007 was $36,000 and $9,000, respectively, which we reduced by $69,000 in each period for the amortization of excess purchase price. We received a distribution from Sandhill of $124,000 and $60,000 during the first quarters of 2008 and 2007, respectively that were attributable to the fourth quarters of the prior years.

Additional discussion of our joint ventures is included in Note 7 of the Notes to the Unaudited Consolidated Financial Statements.

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Supply and Logistics Segment

Our supply and logistics segment was previously known as our crude oil gathering and marketing segment. With the acquisition of the Davison businesses, we renamed the segment and we included the petroleum products, fuel logistics, terminaling, and truck transportation activities we acquired from the Davisons.

Our crude oil gathering and marketing operations are concentrated in Texas, Louisiana, Alabama, Florida, and Mississippi. Those operations - which involve purchasing, gathering, and transporting by trucks and pipelines operated by us and trucks, pipelines and barges operated by others, and reselling - help to ensure (among other things) a base supply source for our crude oil pipeline systems. Our profit for those services is derived from the difference between the price at which we re-sell oil less the price at which we purchase that crude oil, minus the associated costs of aggregation and any cost of supplying credit. The most substantial component of our aggregating costs relates to operating our fleet of leased trucks. Our crude oil gathering and marketing activities provide us with an extensive expertise, knowledge base, and skill set that facilitates our ability to capitalize on regional opportunities which arise from time to time in our market areas. Usually, this segment experiences limited commodity price risk because we generally make back-to-back purchases and sales, matching our sale and purchase volumes on a monthly basis.

When the crude oil markets are in contango (oil prices for future deliveries are higher than for current deliveries), we may purchase and store crude oil as inventory for delivery in future months. When we purchase this inventory, we simultaneously enter into a contract to sell the inventory in the future period for a higher price, either with a counterparty or in the crude oil futures market. The maximum storage capacity available to us for use in this strategy is approximately 120,000 barrels, although maintenance activities on our pipelines impact the availability of this storage capacity. We generally will account for this inventory and the related derivative hedge as a fair value hedge in accordance with Statement of Financial Accounting Standards No. 133. See Note 14 of the Notes to the Unaudited Consolidated Financial Statements.

With the Davison acquisition, we gained approximately 225 trucks, 525 trailers, and 1.3 million barrels of existing leased and owned storage and expanded our activities to include transporting, storing and blending intermediate and finished refined products. In our petroleum products marketing operations, we primarily supply fuel oil, asphalt, diesel, and gasoline to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing their products that do not meet the specifications they desire, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers. The opportunities to provide this service cannot be predicted, but their contribution to margin as a percentage of their revenues tends to be higher than in the same percentage attributable to our recurring operations.

Most of our contracts for the purchase and sale of crude oil have components in the pricing provisions such that the price paid or received is adjusted for changes in the market price for crude oil. The pricing in the majority of our purchase contracts contain the market price component, an unfixed bonus that is based on another market factor and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts will sometimes also contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

In our petroleum products marketing operations, we primarily supply fuel oil, asphalt, petroleum feedstocks, diesel and gasoline to wholesale markets and some end-users such as paper mills and utilities. The opportunities to purchase some of these products cannot be predicted, but the contribution to margin tends to be higher than in our recurring operations.

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Operating results from our supply and logistics segment were as follows:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Supply and logistics revenue	$	430,118		$	173,279
Crude oil and products costs		(407,275	)		(167,722	)
Operating costs		(16,582	)		(3,958	)
Segment margin	$	6,261		$	1,599

Three Months Ended March 31, 2008 as Compared to Three Months Ended March 31, 2007

The portions of our supply and logistics operations acquired in the Davison transaction added approximately $3.6 million to our supply and logistics segment margin for the three months ended March 31, 2008.

Our existing crude oil gathering and marketing operations contribution for the three months ended March 31, 2008 was $1.0 million greater than the contribution for the three months ended March 31, 2007, with the improvement primarily related to improved margin from crude oil sales. Grade differentials related to the chemical composition of the crude oil and the desire in the market for that grade of crude oil create fluctuations in the differentials that can improve or reduce the margin we make on our crude oil transactions. During the first quarter of 2008 those grade differentials combined with volumetric gains and changes in other contract terms improved our margins from the sale of crude oil by $1.5 million.

Crude oil volumes that we transported for a fee, but did not purchase, decreased by 942 barrels per day, however increases in trucking fees between the two periods resulted in a total increase of $0.3 million.

Offsetting the increase in revenues from the crude oil margins and transportation was an increase of $0.8 million in field costs between the 2008 and 2007 first quarters. Fuel costs to operate our fleet of crude oil vehicles increased $0.3 million as diesel prices increased 36%. Compensation costs to operate the trucks and manage our crude oil gathering operations increased $0.3 million, as a result of compensation increases. Expense related to our stock appreciation rights plan decreased by $0.4 million between the periods. Repairs to trucks and equipment, including regulatory testing of our Port Hudson terminal facility, accounted for most of the remaining $0.6 million increase in costs.

If we had owned the assets acquired in the Davison transaction during the first quarter of 2007, our estimated pro forma segment margin would have been approximately $5.9 million. The difference from our actual results for the first quarter of 2008 not attributable to our existing crude oil operations is $0.7 million. Significant factors affecting the operations of the Davison assets include the availability of products for our use in blending to a quality that meets the requirements of our customers and the costs of the transportation services we provide. A key factor influencing our transportation services is the price of diesel for operating our trucks. We use over one million gallons of diesel fuel per quarter. While we include fuel price adjustments in the pricing for many of our transportation services to third parties, we can experience timing differences between when we pay higher prices for the fuel and when we are able to pass that cost through to our customers in some situations.

Other Costs, Interest, and Income Taxes

General and administrative expenses. General and administrative expenses consisted of the following:

	Three Months Ended March 31,
	2008			2007
	(in thousands)

Expenses excluding bonus expense and effects of stock appreciation rights plan	$	8,223		$	2,539
Bonus plan expense		1,163			446
Stock appreciation rights plan (credit) expense		(862	)		343
Total general and administrative expenses	$	8,524		$	3,328

Between the first quarter periods, general and administrative expenses increased by $5.2 million. This increase resulted from an increase related to the administrative personnel and costs at the Davison locations totaling $2.7 million, offset partially by a credit to general and administrative expense for our stock appreciation rights plan that resulted in a total reduction in expense between the periods of $1.2 million. Bonus plan expense increased $0.7 million between the two periods due to the additional personnel from the Davison acquisition. The remaining change in general and administrative expenses totals $3.0 million. The majority of this increase is due to additional fees for audit, tax and other consulting services.

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Depreciation and amortization expense. Depreciation and amortization expense increased in the three month periods primarily as a result of the depreciation and amortization expense recognized on the fixed and intangible assets acquired in the Davison and Port Hudson transactions. This additional depreciation and amortization totaled $14.9 million.

The intangibles acquired in the Davison acquisition are being amortized over the period during which the intangible asset is expected to contribute to our future cash flows. As intangible assets such as customer relationships and trade names are generally most valuable in the first years after an acquisition, the amortization we will record on these assets will be greater in the initial years after the acquisition. As a result, we expect to record significantly more amortization expense related to our intangible assets in 2008 through 2010 than in years subsequent to that time. See Note 6 to the Unaudited Consolidated Financial Statements for information on the amount of amortization we expect to record in each of the next five years.

Interest expense, net.

Interest expense, net was as follows:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Interest expense, including commitment fees	$	1,674		$	209
Capitalized interest		(53	)		(6	)
Amortization of facility fees		165			67
Interest income		(117	)		(44	)
Net interest expense	$	1,669		$	226

As a result of the Davison acquisition which was partially financed with borrowings under our credit facility beginning on July 25, 2007, our interest expense increased $1.4 million between the first quarters. Our average outstanding balance of debt was $76 million during the first quarter of 2008, an increase of $72 million over the prior year period. Our average interest rate on our borrowings during the 2008 quarter was 6.15%, a decrease of 2.60% from the first quarter of 2007.

Income taxes.

Only a small portion of the operations we acquired in the Davison transaction are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, the income tax expense we record relates only to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. In the 2008 first quarter, we recorded an income tax benefit related to the operations of those corporations. .

New and Proposed Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2, “Recent Accounting Developments” in the accompanying unaudited consolidated financial statements.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, and other such references are forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “strategy” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. 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 or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:

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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 or “NGLs,” sodium hydrosulfide and caustic soda 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 liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;

shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, natural gas, or other products or to whom we sell such products;

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 financial covenants;

loss of key personnel;

the effects of competition, in particular, by other pipeline systems;

hazards and operating risks that may not be covered fully by insurance;

the condition of the capital markets in the United States;

loss of key customers;

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 1A of our Annual Report on Form 10-K for the year ended December 31, 2007. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, NaOH prices, and interest rates. Our policy is to purchase only commodity products for which we have a market, and to structure our sales contracts so that price fluctuations for those products do not materially affect the segment margin we receive. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes, as these activities could expose us to significant losses.

Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. Our risk management policies are designed to monitor our physical volumes, grades, and delivery schedules to ensure our hedging activities address the market risks that are inherent in our gathering and marketing activities.

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We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market price fluctuations as needed. All of our open commodity price risk derivatives at March 31, 2008 were categorized as non-trading. On March 31, 2008, we had entered into NYMEX future contracts that settled during April 2008 and NYMEX options contracts that settled during April 2008. Although the intent of our risk-management activities is to hedge our margin, none of our derivative positions at March 31, 2008 qualified for hedge accounting.

The table below presents information about our open derivative contracts at March 31, 2008. Notional amounts in barrels, the weighted average contract price, total contract amount, and total fair value amount in U.S. dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels multiplied by the March 31, 2008 quoted market prices on the NYMEX. All of the hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the table below.

This accounting treatment is discussed further under Note 2 “Summary of Significant Accounting Policies” of our Consolidated Financial Statements in our 2007 Annual Report on Form 10-K. Also see Notes 14 and 17 to the Unaudited Consolidated Financial Statements for additional information on our derivative transactions and fair value measurements of those derivatives.

	Sell (Short)			Buy (Long)
	Contracts			Contracts
Futures Contracts:

Crude Oil:
Contract volumes (1,000 bbls)		54			50
Weighted average price per bbl	$	104.78		$	103.92

Contract value (in thousands)	$	5,658		$	5,196
Mark-to-market change (in thousands)		(173	)		(117	)
Market settlement value (in thousands)	$	5,485		$	5,079

RBOB Gasoline:
Contract volumes (1,000 bbls)		5			3
Weighted average price per bbl	$	114.64		$	110.34

Contract value (in thousands)	$	573		$	331
Mark-to-market change (in thousands)		(21	)		-
Market settlement value (in thousands)	$	552		$	331

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	Sell (Short)
	Contracts
NYMEX Option Contracts:

Crude Oil-Written Calls:
Contract volumes (1,000 bbls)		45
Weighted average premium received	$	12.15

Contract value (in thousands)	$	547
Mark-to-market change (in thousands)		(201	)
Market settlement value (in thousands)	$	346

Heating Oil-Written Puts:
Contract volumes (1,000 bbls)		9
Weighted average premium received	$	1.97

Contract value (in thousands)	$	18
Mark-to-market change (in thousands)		4
Market settlement value (in thousands)	$	22

Heating Oil-Written Calls:
Contract volumes (1,000 bbls)		9
Weighted average premium received	$	4.12

Contract value (in thousands)	$	37
Mark-to-market change (in thousands)		(13	)
Market settlement value (in thousands)	$	24

RBOB Gasoline-Written Puts:
Contract volumes (1,000 bbls)		10
Weighted average premium received	$	3.13

Contract value (in thousands)	$	31
Mark-to-market change (in thousands)		(12	)
Market settlement value (in thousands)	$	19

We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts.

We are also exposed to market risks due to the floating interest rates on our credit facility. Our debt bears interest at the LIBOR Rate or Prime Rate, at our option, plus the applicable margin. We do not hedge our interest rates. The carrying values of our debt approximate fair value primarily because interest rates fluctuate with prevailing market rats, and the credit spread on outstanding borrowings reflect market. On March 31, 2008, we had $82.0 million of debt outstanding under our credit facility.

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. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

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There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Davison Acquisition

On July 25, 2007, we completed the Davison Acquisition, which met the criteria of being a significant acquisition for us. For additional information regarding the acquisition, please read Note 3 to the Unaudited Consolidated Financial Statements included in Item 1 in this Quarterly Report on Form 10-Q.

On June 22, 2004, the Office of the Chief Accountant of the SEC issued guidance regarding the reporting of internal control over financial reporting in connection with a major acquisition. On October 6, 2004, the SEC revised its guidance to include expectations of quarterly reporting updates of new internal control and the status of the control regarding any exempted businesses. This guidance was reiterated in September 2007 to affirm that management may omit an assessment of an acquired business’ internal control over financial reporting from management’s assessment of internal control over financial reporting for a period not to exceed one year.

We excluded the operations acquired in the Davison Acquisition from the scope of our Sarbanes-Oxley Section 404 report on internal control over financial reporting for the year ended December 31, 2007. A summary of the reasons for this exclusion is under Item 9A of our 2007 Annual Report on Form 10-K.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I. Item 1. See Note 15 of the Notes to the Unaudited Consolidated Financial Statements entitled “Contingencies,” which is incorporated herein by reference.

Item 1A. Risk Factors.

There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

See Note 8 of the Notes to the Unaudited Consolidated Financial Statements.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None.

Item 6. Exhibits.

(a)

Exhibits.

3.1		Certificate of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545)

3.2		Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15, 2005)

3.3		Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 2007.)

3.4		Certificate of Limited Partnership of Genesis Crude Oil, L.P. (“the Operating Partnership”) (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996)

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3.5		Fourth Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated June 15, 2005)

3.6		Certificate of Incorporation of Genesis Energy, Inc. (incorporated by reference to Exhibit 3.6 to Form 10-K for the year ended December 31, 2007.)

3.7		Certificate of Amendment of Certificate of Incorporation of Genesis Energy, Inc. (incorporated by reference to Exhibit 3.7 to Form 10-K for the year ended December 31, 2007.)

3.8		Bylaws of Genesis Energy, Inc. (incorporated by reference to Exhibit 3.8 to Form 10-K for the year ended December 31, 2007.)

4.1		Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007.)

10.1	*	Amendment to the First Amendment to Credit Agreement and Guarantee and Collateral Agreement dated as of March 28, 2008.

31.1	*	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.

31.2	*	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.

32	*	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.

*Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		GENESIS ENERGY, L.P.
		(A Delaware Limited Partnership)
	By:	GENESIS ENERGY, INC.,
		as General Partner


Date: May 9, 2008	By:	/s/ Ross A. Benavides
		Ross A. Benavides
		Chief Financial Officer

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