Genesis Energy (GEL) 8-K Other Events

Exhibit 99.3

GENESIS ENERGY, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

	Page
Financial Statements
Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets, December 31, 2008 and 2007	3
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	4
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006	5
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2008, 2007 and 2006	6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	7
Notes to Consolidated Financial Statements	8
Financial Statement Schedules
Schedule I – Condensed Financial Information (Parent Company Only)	48
All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to the consolidated financial statements.

1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Genesis Energy, LLC and Unitholders of

Genesis Energy, L.P.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P. and subsidiaries (the “Partnership”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. Our audit also included the financial statement schedule listed in the Index on page one. These financial statements and financial statement schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Genesis Energy, L.P. and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As described in Note 2 to the consolidated financial statements and effective as of January 1, 2008, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 157,Fair Value Measurements, which established new accounting and reporting standards for fair value measurements of certain financial assets and liabilities. As also discussed in Note 2 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the adoption of SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 and Emerging Issues Task Force (“EITF”) 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2009 (not presented herein) expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/    DELOITTE & TOUCHE LLP

Houston, Texas

March 11, 2009

(January 22, 2010 as to the effects of the adoption of SFAS No. 160 and EITF 07-4 and the related disclosures in Note 2)

2

GENESIS ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,985		$	11,851
Accounts receivable - trade, net of allowance for doubtful accounts of $1,132 at December 31, 2008		112,229			178,658
Accounts receivable - related party		2,875			1,441
Inventories		21,544			15,988
Net investment in direct financing leases, net of unearned income - current portion - related party		3,758			609
Other		8,736			5,693
Total current assets		168,127			214,240
FIXED ASSETS, at cost		349,212			150,413
Less: Accumulated depreciation		(67,107	)		(48,413	)
Net fixed assets		282,105			102,000
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related party		177,203			4,764
CO2 ASSETS, net of amortization		24,379			28,916
EQUITY INVESTEES AND OTHER INVESTMENTS		19,468			18,448
INTANGIBLE ASSETS, net of amortization		166,933			211,050
GOODWILL		325,046			320,708
OTHER ASSETS, net of amortization		15,413			8,397
TOTAL ASSETS	$	1,178,674		$	908,523
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	96,454		$	154,614
Accounts payable - related party		3,105			2,647
Accrued liabilities		26,713			17,537
Total current liabilities		126,272			174,798
LONG-TERM DEBT		375,300			80,000
DEFERRED TAX LIABILITIES		16,806			20,087
OTHER LONG-TERM LIABILITIES		2,834			1,264
COMMITMENTS AND CONTINGENCIES (Note 19)
PARTNERS’ CAPITAL:
Common unitholders, 39,457 and 38,253 units issued and outstanding at December 31, 2008 and 2007, respectively		616,971			615,265
General partner		16,649			16,539
Accumulated other comprehensive loss		(962	)		—
Total Genesis Energy, L.P. partners’ capital		632,658			631,804
Noncontrolling interests		24,804			570
Total partners’ capital		657,462			632,374
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,178,674		$	908,523

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

3

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Year Ended December 31,
	2008			2007			2006
REVENUES:
Supply and logistics:
Unrelated parties (including revenues from buy/sell arrangements of $69,772 in 2006)	$	1,847,575		$	1,092,398		$	872,443
Related parties		4,839			1,791			825
Refinery services		225,374			62,095			—
Pipeline transportation, including natural gas sales:
Transportation services - unrelated parties		19,469			17,153			17,119
Transportation services - related parties		21,730			5,754			4,948
Natural gas sales revenues		5,048			4,304			7,880
CO2 marketing:
Unrelated parties		15,423			13,376			13,098
Related parties		2,226			2,782			2,056
Total revenues		2,141,684			1,199,653			918,369
COSTS AND EXPENSES:
Supply and logistics costs:
Product costs - unrelated parties (including costs from buy/sell arrangements of $68,899 in 2006)		1,736,637			1,041,637			850,106
Product costs - related parties		—			101			1,565
Operating costs		78,453			37,121			14,231
Refinery services operating costs		166,096			40,197			—
Pipeline transportation costs:
Pipeline transportation operating costs		10,306			10,054			9,928
Natural gas purchases		4,918			4,122			7,593
CO2 marketing costs:
Transportation costs - related party		6,424			5,213			4,640
Other costs		60			152			202
General and administrative		29,500			25,920			13,573
Depreciation and amortization		71,370			38,747			7,963
Net loss (gain) on disposal of surplus assets		29			266			(16	)
Impairment expense		—			1,498			—
Total costs and expenses		2,103,793			1,205,028			909,785
OPERATING INCOME (LOSS)		37,891			(5,375	)		8,584
Equity in earnings of joint ventures		509			1,270			1,131
Interest income		458			385			198
Interest expense		(13,395	)		(10,485	)		(1,572	)
Income (loss) before income taxes		25,463			(14,205	)		8,341
Income tax benefit		362			654			11
Income (loss) before cumulative effect adjustment		25,825			(13,551	)		8,352
Cumulative effect adjustment of adoption of new accounting principle		—			—			30
NET INCOME (LOSS)		25,825			(13,551	)		8,382
Net income (loss) attributable to noncontrolling interests		264			1			(1	)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	26,089		$	(13,550	)	$	8,381

4

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED

(In thousands, except per unit amounts)

	Year Ended December 31,
	2008		2007			2006
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. PER COMMON UNIT:
BASIC	$	0.59	$	(0.66	)	$	0.59
DILUTED	$	0.59	$	(0.66	)	$	0.59
OUTSTANDING COMMON UNITS:
BASIC		38,961		20,754			13,784
DILUTED		39,025		20,754			13,784

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

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Year Ended December 31,
	2008			2007			2006
Net income (loss)	$	25,825		$	(13,551	)	$	8,382
Changes in derivative financial instruments - interest rate swaps		(1,964	)		—			—
Comprehensive income (loss)		23,861			(13,551	)		8,382
Comprehensive income attributable to noncontrolling interests		1,266			1			(1	)
Comprehensive income attributable to Genesis Energy, L.P.	$	25,127		$	(13,550	)	$	8,381

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

5

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

	Partners’ Capital
	Number of Common Units		Common Unitholders			General Partner			Accumulated Other Comprehensive Loss			Non- controlling Interests		Total
Partners’ capital, January 1, 2006	13,784		$	85,870		$	1,819		$	—		522		$	88,211
Comprehensive income:
Net income	—			8,214			167			—		1			8,382
Cash distributions	—			(10,200	)		(208	)		—		(1	)		(10,409	)
Partners’ capital, December 31, 2006	13,784			83,884			1,778			—		522			86,184
Comprehensive income:
Net loss	—			(13,279	)		(271	)		—		(1	)		(13,551	)
Cash contributions	—			—			1,412			—		—			1,412
Contribution for management compensation (Note 11)	—			—			3,434			—		—			3,434
Cash distributions	—			(16,743	)		(432	)		—		(2	)		(17,177	)
Issuance of units	24,469			561,403			10,618			—		51			572,072
Partners’ capital, December 31, 2007	38,253			615,265			16,539			—		570			632,374
Comprehensive income:
Net income	—			23,485			2,604			—		(264	)		25,825
Interest rate swap loss	—			—			—			(962	)	(1,002	)		(1,964	)
Cash contributions	—			—			511			—		25,505			26,016
Cash distributions	—			(47,529	)		(3,005	)		—		(5	)		(50,539	)
Issuance of units	2,037			41,667			—			—		—			41,667
Unit based compensation expense	5			750			—			—		—			750
Redemption of units	(838	)		(16,667	)		—			—		—			(16,667	)
Partners’ capital, December 31, 2008	39,457			616,971			16,649			(962	)	24,804			657,462

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

6

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	25,825		$	(13,551	)	$	8,382
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Depreciation and amortization		71,370			40,245			7,963
Amortization and write-off of credit facility issuance costs		1,437			779			969
Amortization of unearned income and initial direct costs on direct financing leases		(10,892	)		(620	)		(655	)
Payments received under direct financing leases		11,519			1,188			1,186
Equity in earnings of investments in joint ventures		(509	)		(1,270	)		(1,131	)
Distributions from joint ventures - return on investment		1,272			1,845			1,565
Non-cash effect of unit-based compensation plans		(2,063	)		910			1,929
Non-cash compensation charge		—			3,434			—
Deferred and other tax liabilities		(2,771	)		(2,658	)		(11	)
Other non-cash items		882			347			(62	)
Net changes in components of operating assets and liabilities, net of working capital acquired (See Note 14)		(1,262	)		3,280			(8,873	)
Net cash provided by operating activities		94,808			33,929			11,262
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed assets		(37,354	)		(8,235	)		(1,260	)
CO2 pipeline transactions and related costs		(228,891	)		—			—
Distributions from joint ventures - return of investment		886			395			528
Investments in joint ventures and other investments		(2,397	)		(1,104	)		(6,042	)
Acquisition of Grifco assets		(65,693	)		—			—
Acquisition of Davison assets, net of cash acquired		(993	)		(301,640	)		—
Acquisition of Port Hudson assets		—			(8,103	)		—
Other, net		718			(2,655	)		(68	)
Net cash used in investing activities		(333,724	)		(321,342	)		(6,842	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		531,712			392,200			8,000
Bank repayments		(236,412	)		(320,200	)		—
Additional purchase price consideration paid to Grifco		(6,000	)		—			—
Credit facility issuance fees		(2,255	)		(2,297	)		(2,726	)
Issuance of common units for cash		—			231,433			—
Redemption of common units for cash		(16,667	)		—			—
General partner contributions		511			12,030			—
Noncontrolling interests’ contributions, net of distributions		25,500			49			(1	)
Distributions to common unitholders		(47,529	)		(16,743	)		(10,200	)
Distributions to general partner interest		(3,005	)		(432	)		(208	)
Other, net		195			906			(66	)
Net cash provided by (used in) financing activities		246,050			296,946			(5,201	)
Net increase (decrease) in cash and cash equivalents		7,134			9,533			(781	)
Cash and cash equivalents at beginning of period		11,851			2,318			3,099
Cash and cash equivalents at end of period	$	18,985		$	11,851		$	2,318

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

7

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. 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, carbon dioxide (or CO₂) and, to a lesser degree, natural gas;

• 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 and barge of crude oil and petroleum products.

Our 2% general partner interest is held by Genesis Energy, LLC, a Delaware limited liability company and an indirect, majority-owned subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. Our general partner and its affiliates also own 10.2% 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.

2. Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2008 and 2007 and our results of operations, cash flows and changes in partners’ capital for the years ended December 31, 2008, 2007 and 2006. All intercompany transactions have been eliminated. The accompanying consolidated financial statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries.

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.

Joint Ventures

We participate in three joint ventures: DG Marine Transportation, LLC (DG Marine), T&P Syngas Supply Company (T&P Syngas) and Sandhill Group, LLC (Sandhill). As of the acquisition date in July 2008, DG Marine is consolidated in our financial statements. We account for our 50% investments in T&P Syngas and Sandhill by the equity method of accounting. See Note 8.

DG Marine Transportation, LLC

In July 2008, we acquired an interest in DG Marine which acquired the inland marine transportation business of Grifco Transportation, Ltd and two of its affiliates. DG Marine is a joint venture with TD Marine, LLC, an entity owned by members of the Davison family. We own an effective 49% economic interest and TD Marine, LLC owns a 51% economic interest in DG Marine. TD Marine, LLC controls the DG Marine joint venture and the day-to-day operations are conducted by and managed by DG Marine employees. The provisions of Financial Interpretation No. 46(R) “Consolidation of Variable Interest Entities” (FIN 46R), require us to consolidate DG Marine in our consolidated financial statements. See Note 3. The results of the operations of DG Marine have been included in our consolidated financial statements since the date of the acquisition.

8

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

T&P Syngas Supply Company

We own a 50% interest in 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.

Sandhill Group, LLC

We own a 50% interest in Sandhill. At December 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.

Noncontrolling Interests

Our general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P. and TD Marine, LLC, a related party, owns the remaining 51% economic interest in DG Marine. The net interest of those parties in our results of operations and financial position are reflected in our financial statements as noncontrolling interests.

In July 2007, we acquired the energy-related businesses of the Davison family. See Note 3. The results of the operations of these businesses have been included in our consolidated financial statements since August 1, 2007.

Use of Estimates

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) estimated useful lives of assets, which impacts depreciation and amortization, (2) liability and contingency accruals, (3) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (4) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (5) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding the expected life of the rights, expected forfeiture rates of the rights, volatility of our unit price and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Partnership has no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

Accounts Receivable

Our accounts receivable are primarily from purchasers of crude oil and petroleum products, and, to a lesser extent, purchasers of NaHS and CO₂. These purchasers include refineries, marketing and trading companies. The majority of our accounts receivable relate to our supply and logistics activities that can be described as high volume and low margin activities.

Volatility in the financial markets in the latter half of 2008 combined with significant energy price volatility has caused liquidity issues impacting many companies, which in turn have increased the potential credit risks associated with certain counterparties with which we do business. We utilize our credit review process to monitor these conditions and to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require.

We review our outstanding accounts receivable balances on a regular basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.

9

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the activity of our allowance for doubtful accounts for the year ended December 31, 2008:

	Year Ended December 31, 2008
Balance at beginning of period	$	—
Charged to costs and expenses		1,152
Amounts written off		(20	)
Balance at end of period	$	1,132

Inventories

Crude oil and petroleum products inventories held for sale are valued at the lower of average cost or market. Fuel inventories are carried at the lower of cost or market. Caustic soda and NaHS inventories are stated at the lower of cost or market. Cost is determined principally under the average cost method within specific inventory pools.

Fixed Assets

Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 15 years for pipelines and related assets, 25 years for push boats and barges, 10 to 20 years for machinery and equipment, 40 years for tanks, 3 to 7 years for vehicles and transportation equipment, and 3 to 10 years for buildings, office equipment, furniture and fixtures and other equipment.

Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life.

Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset.

Certain volumes of crude oil are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil volumes are carried at their weighted average cost.

Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows.

Asset Retirement Obligations

Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our future asset retirement obligations relate to future costs associated with the removal of our oil, natural gas and CO₂ pipelines, barge decommissioning, 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. See Note 5.

Direct Financing Leasing Arrangements

We lease four pipelines to Denbury under direct financing leases. Three of these leases of pipeline segments to Denbury will expire in 2013 to 2015. The NEJD Pipeline System lease to Denbury will expire in 2028, subject to certain extension options.

10

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

When a direct financing lease is consummated, we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in pipeline revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets. See Note 6.

CO₂ Assets

Our CO₂ assets include three volumetric production payments and long-term contracts to sell the CO₂ volume. The contract values are being amortized on a units-of-production method. See Note 7.

Intangible Assets

Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (SFAS 142) requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We are recording amortization of our customer and supplier relationships, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows 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.

We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. As of December 31, 2008, no impairment has occurred of intangible assets.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. We account for goodwill under SFAS 142, which prohibits amortization of goodwill, but instead requires testing for impairment at least annually. We test goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. In the event that we determine that goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made. See Note 9.

Environmental Liabilities

We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.

Unit-Based Compensation

On January 1, 2006, we adopted the provisions of SFAS No. 123(R), “Share-Based Payments”. This statement requires that the compensation cost associated with our stock appreciation rights plan, which upon exercise will result in the payment of cash to the employee, be re-measured each reporting period based on the fair value of the rights. Before the adoption of SFAS 123(R), we accounted for the stock appreciation rights in accordance with FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans” which required that the liability under the plan be measured at each balance sheet date based on the market price of our common units on that date. Under SFAS 123(R), the liability is calculated using a fair value method that takes into consideration the expected future value of the rights at their expected exercise dates.

Our 2007 Long-term Incentive Plan provides for awards of phantom units to our non-employee directors and to the employees of our general partner. SFAS No. 123(R) requires that compensation cost related to phantom units issued under our 2007 Long-term Incentive Plan be recognized in our consolidated financial statements based on estimated fair value at the date of the grant. See Note 15.

11

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 31, 2008, our general partner awarded Class B Membership Interests in our general partner to our senior executives. SFAS 123(R) requires that the compensation cost related to these interests be re-measured at each reporting date based on the fair value of the interests, and changes in that fair value be recognized over the vesting period. Recorded expense will be subsequently adjusted to fair value until final settlement. See Note 15.

Revenue Recognition

Product Sales - Revenues from the sale of crude oil, petroleum products, natural gas, caustic soda and NaHS are recognized when title to the inventory is transferred to the customer, collectibility is reasonably assured and there are no further significant obligations for future performance by us. Most frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although in certain situations, title transfers when the inventory is loaded for transportation to the customer. Our crude oil, natural gas and petroleum products are typically sold at prices based off daily or monthly published prices. Many of our contracts for sales of NaHS incorporate the price of caustic soda in the pricing formulas.

Pipeline Transportation - Revenues from transportation of crude oil or natural gas by our pipelines are based on actual volumes at a published tariff. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to the specifications outlined in our regulated tariffs.

In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs include the right for us to make volumetric deductions from the shippers for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances.

We compare these allowances to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or expense, based on prevailing market prices at that time. When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand and record a liability for the purchase of crude oil that we must make to replace the lost volumes. We reflect inventories in the financial statements at the lower of the recorded value or the market value at the balance sheet date. We value liabilities to replace crude oil at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value.

Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline revenues.

CO₂ Sales - Revenues from CO₂ marketing activities are recorded when title transfers to the customer at the inlet meter of the customer’s facility.

Cost of Sales and Operating Expenses

Supply and logistics costs and expenses include the cost to acquire the product and the associated costs to transport it to our terminal facilities or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks and barges, including personnel costs, fuel and maintenance of our equipment.

When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions as a net amount in our consolidated statements of operations beginning with April 2006. Transactions for periods prior to April 2006 are not reflected as a net amount; however the amounts are disclosed parenthetically on the consolidated statements of operations, in accordance with the provision of Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” Had this provision been in effect in the first quarter of 2006, our reported supply and logistics revenues from unrelated parties for the year ended December 31, 2006 would have been reduced by $69 million to $803 million. Our reported supply and logistics product costs from unrelated parties for the year ended December 31, 2006 would have been reduced by $69 million to $781 million. This change had no effect on operating income, net income or cash flows.

The most significant operating costs in our refinery services segment consist of the costs to operate NaHS plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas stream, and costs to transport the NaHS and caustic soda.

Pipeline operating costs consist primarily of power costs to operate pumping equipment, personnel costs to operate the pipelines, insurance costs and costs associated with maintaining the integrity of our pipelines.

12

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cost of sales for the CO₂ marketing activities consists of a transportation fee charged by Denbury to transport the CO₂ to the customer through Denbury’s pipeline and insurance costs. The transportation fee charged by Denbury is adjusted annually for inflation. For the years ended December 31, 2008, 2007 and 2006, the fee averaged $0.1927, $0.1848 and $0.1740 per Mcf, respectively.

Excise and Sales Taxes

The Company collects and remits excise and sales taxes to state and federal governmental authorities on its sales of fuels. These taxes are presented on a net basis, with any differences due to rebates allowed by those governmental entities reflected as a reduction of product cost in the consolidated income statements.

Income Taxes

We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of operations, is includable in the federal income tax returns of each partner.

Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the consolidated statements of operations.

Derivative Instruments and Hedging Activities

We minimize our exposure to price risk by limiting our inventory positions. However when we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. DG Marine uses interest rate swap contracts to manage its exposure to interest rate risk.

We account for those derivative transactions in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended and interpreted. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded on the balance sheet as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. See Note 17.

Fair Value of Current Assets and Current Liabilities

The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these instruments are represented in our consolidated balance sheets.

Net Income Per Common Unit

Effective January 1, 2009, we adopted EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (EITF 07-4). EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period. We adopted EITF 07-4 on January 1, 2009. The requirements of EITF 07-4 have been applied retrospectively to the Consolidated Financial Statements and Notes.

13

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent and Proposed Accounting Pronouncements

Implemented in 2008

FASB Staff Position FIN 46(R)-8

In December 2008, the FASB issued FASB Staff Position FIN 46(R)-8, “Disclosures about Variable Interest Entities” (FSP FIN 46(R)-8). FSP FIN 46(R)-8 requires enhanced disclosures about a company’s involvement in variable interest entities (VIEs). The enhanced disclosures required by this FSP are intended to provide users of financial statements with an greater understanding of: (1) the significant judgments and assumptions made by a company in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE; (2) the nature of restrictions on the assets of a VIE that are consolidated and reported by a company in its statement of financial position, including the carrying amounts of such assets; (3) the nature of, and changes in, the risks associated with a company’s involvement with a VIE; (4) how a company’s involvement with a VIE affects the company’s financial position, financial performance, and cash flows. This FSP was effective for us on December 31, 2008. See Note 3 for disclosures regarding our involvement with VIEs.

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 18 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 was 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.

Implemented January 1, 2009

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 adopted SFAS 141(R) on January 1, 2009. Adoption will impact our accounting for acquisitions we complete subsequent to that date.

14

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 retrospectively adopted SFAS 160 on January 1, 2009. The impact of the retrospective application of this standard is as follows:

• Reclassifies “Minority interest income (loss)” as “Net income (loss) attributable to noncontrolling interests” below “Net income (loss)” in the presentation of “Net income (loss) attributable to Genesis Energy, L.P.” in our Consolidated Statements of Operations for the periods presented.

• Reclassifies “Minority interests” as “Noncontrolling interests” in “Total partners’ capital” in our Consolidated Balance Sheets for all periods presented.

• Separately reflects changes in “Noncontrolling interests” in the Consolidated Statements of Partners’ Capital and Comprehensive Income (Loss) for all periods presented.

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 (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

EITF 07-4

In March 2008, the Emerging Issues Task Force (or EITF) of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128,Earnings per Share, to Master Limited Partnerships” (EITF 07-4). EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. We retrospectively adopted EITF 07-04 on January 1, 2009. The impact of this retrospective adoption changed the calculation of net income (loss) per common unit by adjusting the General Partner incentive distribution from the actual amount paid to the amount to be paid for each period presented. As a result of this adjustment, basic net income per common unit was adjusted by $0.02 for the each of the years ended December 31, 2008 and 2007, and diluted net income per common unit was adjusted by $0.01 and $0.02 for the years ended December 31, 2008 and 2007, respectively.

FASB Staff Position No. 142-3

In April 2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the Useful Life of Intangible Assets” (FSP 142-3). This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset under Statement of Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.” The purpose of this FSP is to develop consistency between the useful life assigned to intangible assets and the cash flows from those assets. FSP 142-3 is effective for fiscal years beginning after December 31, 2008. We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.

15

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Acquisitions

DG Marine Transportation Investment

On July 18, 2008, DG Marine completed the acquisition of the inland marine transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s affiliates. DG Marine is a joint venture we formed with TD Marine, LLC, an entity owned by members of the Davison family. (See discussion below on the acquisition of the Davison family businesses in 2007.). TD Marine owns (indirectly) a 51% economic interest in the joint venture, DG Marine, and we own (directly and indirectly) a 49% economic interest. This acquisition gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.

Grifco received initial purchase consideration of approximately $80 million, comprised of $63.3 million in cash and $16.7 million, or 837,690 of our common units. A portion of the units are subject to certain lock-up restrictions. DG Marine acquired substantially all of Grifco’s assets, including twelve barges, seven push boats, certain commercial agreements, and offices. Additionally, DG Marine and/or its subsidiaries acquired the rights, and assumed the obligations, to take delivery of four new barges in late third quarter of 2008 and four additional new barges late in first quarter of 2009 (at a total price of approximately $27 million). Upon delivery of the eight new barges, the acquisition of three additional push boats (at an estimated cost of approximately $6 million), and after placing the barges and push boats into commercial operations, DG Marine will be obligated to pay additional purchase consideration of up to $12 million. At December 31, 2008, DG Marine had taken delivery of four of the new barges and $6 million of the additional purchase price consideration was paid. At December 31, 2008, the $5.9 million estimated present value of the remaining $6 million obligation is included in “Accrued Liabilities” in our consolidated balance sheet. The effective interest rate of the obligation was 4.7%

The Grifco acquisition and related closing costs were funded with $50 million of aggregate equity contributions from us and TD Marine, in proportion to our ownership percentages, and with borrowings of $32.4 million under a revolving credit facility which is non-recourse to us and TD Marine (other than with respect to our investments in DG Marine). Although DG Marine’s debt is non-recourse to us, our ownership interest in DG Marine is pledged to secure its indebtedness. We funded our $24.5 million equity contribution with $7.8 million of cash and 837,690 of our common units, valued at $19.896 per unit, for a total value of $16.7 million. At closing, we also redeemed 837,690 of our common units from the Davison family. See Notes 10 and 11.

We have entered into a subordinated loan agreement with DG Marine whereby we may (at our sole discretion) lend up to $25 million to DG Marine. The loan agreement provides for DG Marine to pay us interest on any loans at the rate at which we borrowed funds under our credit facility plus 4%. Those loans will mature on January 31, 2012. Under that subordinated loan agreement, DG Marine is required to make monthly payments to us of principal and interest to the extent DG Marine has any available cash that otherwise would have been distributed to the owners of DG Marine in respect of their equity interest. DG Marine’s revolving credit facility includes restrictions on DG Marine’s ability to make specified payments under the subordinated loan agreement and distributions in respect of our equity interest. At December 31, 2008, there were no amounts outstanding under the subordinated loan agreement. We have, however, provided a $7.5 million guaranty to the lenders under DG Marine’s credit facility. This guaranty will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00 at May 31, 2009.

The provisions of Financial Interpretation No. 46(R) “Consolidation of Variable Interest Entities” (FIN 46R), require the primary beneficiary to consolidate variable interest entities. As stated in FIN 46R, in determining the primary beneficiary of a variable interest entity (“VIE”) that is held between two or more related parties the primary beneficiary is considered to be the party that is “most closely associated” with the VIE. We are considered to be the primary beneficiary due to (i) our involvement in the design of DG Marine, (ii) the ongoing involvement with regards to financial and operating decision making of DG Marine, excluding matters related to new contracts and vessel disposal which are decided solely by TD Marine, and (iii) the financial support we provide to DG Marine. TD Marine has no requirements to make any additional contributions to DG Marine.

As we are considered the primary beneficiary, DG Marine is consolidated in our consolidated financial statements and the 51% ownership interest of TD Marine in the net assets and net income of DG Marine is included in noncontrolling interests in our consolidated financial statements.

16

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The acquisition cost allocated to the assets consists of $63.3 million of cash, $16.7 million of value from the issuance of our limited partnership units to Grifco, $11.7 million related to the discounted value of the additional consideration that will be owed to Grifco when the barges under construction are placed in service and $2.4 million of transaction costs. The acquisition cost has been allocated to the assets acquired based on estimated fair values. Such fair values were developed by management.

The allocation of the acquisition cost is summarized as follows:

Property and equipment	$	91,772
Amortizable intangible assets:
Customer relationships		800
Trade name		900
Non-compete agreements		600
Total allocated cost	$	94,072

The weighted average amortization period for the intangible assets at the date of acquisition is 10 years for customer relationships, 3 years for the trade name and 7 years for the non-compete agreements. The weighted average amortization period for all intangible assets acquired in the Grifco transaction was 6 years.

See additional information on intangible assets and goodwill in Note 9.

At December 31, 2008, our Consolidated Balance Sheets included the following amounts related to DG Marine:

Cash	$	623
Accounts receivable - trade		2,812
Other current assets		859
Fixed assets, at cost		110,214
Accumulated depreciation		(3,084	)
Intangible assets, net		2,208
Other assets		2,178
Total assets	$	115,810
Accounts payable	$	1,072
Accrued liabilities		9,258
Long-term debt		55,300
Other long-term liabilities		1,393
Total liabilities	$	67,023

2008 Denbury Drop-Down Transactions

On May 30, 2008, we completed two “drop-down” transactions with Denbury Onshore LLC, (Denbury Onshore), a wholly-owned subsidiary of Denbury Resources Inc., the indirect owner of our general partner.

NEJD Pipeline System

In 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million and related to Denbury’s North East Jackson Dome (NEJD) Pipeline System. The NEJD Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently being leased and used by Denbury for its Phase I area of tertiary operations in southwest Mississippi. We recorded this lease arrangement in our consolidated financial statements as a direct financing lease. Under the terms of the agreement, Denbury Onshore began making quarterly rent payments beginning August 30, 2008. These quarterly rent payments are fixed at $5,166,943 per quarter or approximately $20.7 million per year during the lease term at an interest rate of 10.25%. At the end of the lease term, we will convey all of our interests in the NEJD Pipeline to Denbury Onshore for a nominal payment.

17

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The NEJD Pipeline System is a 183-mile, 20” CO₂ pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson, Louisiana, currently being used by Denbury for its tertiary operations in southwest Mississippi. Denbury has the rights to exclusive use of the NEJD Pipeline System, will be responsible for all operations and maintenance on that system, and will bear and assume all obligations and liabilities with respect to that system. The NEJD transaction was funded with borrowings under our credit facility.

See additional discussion of this direct financing lease in Note 6.

Free State Pipeline System

We purchased Denbury’s Free State Pipeline for $75 million, consisting of $50 million in cash which we borrowed under our credit facility, and $25 million in the form of 1,199,041 of our common units. The number of common units issued was based on the average closing price of our common units from May 28, 2008 through June 3, 2008.

The Free State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO₂ source fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in east Mississippi. We entered into a twenty-year transportation services agreement to deliver CO₂ on the Free State pipeline for Denbury’s use in its tertiary recovery operations. Under the terms of the transportation services agreement, we are responsible for owning, operating, maintaining and making improvements to that pipeline. Denbury has rights to exclusive use of that pipeline and is required to use that pipeline to supply CO₂ to its current and certain of its other tertiary operations in east Mississippi. The transportation services agreement provides for a $100,000 per month minimum payment, which is accounted for as an operating lease, plus a tariff based on throughput. Denbury has two renewal options, each for five years on similar terms. Any sale by us of the Free State Pipeline and related assets or of an ownership interest in our subsidiary that holds such assets would be subject to a right of first refusal purchase option in favor of Denbury.

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”). 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.

For financial reporting purposes, the consideration for this acquisition consisted of $623 million of value, net of cash acquired. The consideration is comprised of $293 million in cash, (which is net of $21.7 million of cash acquired), and 13,459,209 common units of Genesis valued at $330 million. In accordance with EITF, No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of Genesis common units issued was determined using an average price of $24.52, which was the average closing price of Genesis common units for the two days before and after the date on which the terms of the acquisition were agreed to and announced. The direct transaction costs totaled $8.9 million and consist primarily of legal and accounting fees and other external costs related directly to the acquisition.

The Davison family is our largest unitholder, with approximately 33% of our outstanding common units. It has designated two of the family members to the board of directors of our general partner, and as long as it maintains a specified minimum percentage of our common units, it will have the continuing right to designate up to two directors. The Davison family has agreed to restrictions that limit its ability to sell specified percentages of its common units through July 26, 2010. Pursuant to an agreement between us and the Davison unitholders, the Davison unitholders have registration rights with respect to their common units. These rights include the right to require us to file a Form S-3 shelf registration statement, if we are eligible.

18

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated fair values. Such fair values were developed by management. The allocation of the purchase price is summarized as follows:

Cash and cash equivalents	$	21,686
Accounts receivable		55,631
Inventories		10,825
Other current assets		982
Other assets		294
Property and equipment		67,655
Goodwill		316,739
Amortizable intangible assets:
Customer relationships		129,284
Supplier agreements		36,469
Licensing agreements		38,678
Trade name		17,988
Covenants not-to-compete		695
Favorable lease agreement		13,260
Accounts payable and accrued expenses		(35,230	)
Deferred tax liabilties assumed		(21,794	)
Total allocation	$	653,162

See additional information on intangible assets and goodwill in Note 9. Goodwill represents the residual of the purchase price over the fair value of net tangible and identifiable intangible assets acquired.

The following table presents selected unaudited pro forma financial information incorporating the historical operating results of the Davison businesses. The effective closing date of our purchase of the Davison businesses was July 25, 2007. As a result, our Consolidated Statements of Operations for the year ended December 31, 2007 includes five months of results of operations of these acquired businesses. The pro forma financial information has been prepared as if the acquisition had been completed on the first day of each period presented rather than the actual closing date. The pro forma financial information has been prepared based upon assumptions deemed appropriate by us and may not be indicative of actual results.

	Year Ended December 31,
	2007			2006
Pro Forma Earnings Data:
Revenue	$	1,574,730		$	1,479,174
Costs and expenses		1,572,809			1,477,275
Operating income		1,921			1,899
(Loss) Income before extraordinary items		(29,666	)		(19,664	)
Net (loss) income attributable to Genesis Energy, L.P.		(29,666	)		(19,664	)
Basic and diluted (loss) earnings per unit attributable to Genesis Energy, L.P.:
As reported units outstanding		20,754			13,784
Pro forma units outstanding		28,319			28,319
As reported net (loss) income per unit	$	(0.66	)	$	0.59
Pro forma net (loss) income per unit	$	(1.07	)	$	(0.69	)

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 acquisition was funded with borrowings under our credit facility.

19

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The purchase price has been allocated to the assets acquired based on estimated fair values. The allocation of the purchase price is summarized as follows:

Property and equipment	$	4,134
Goodwill		3,969
Total	$	8,103

See additional information on goodwill in Note 9.

4. Inventories

The major components of inventories were as follows:

	December 31,
	2008		2007
Crude oil		1,878		3,710
Petroleum products		5,589		6,527
Caustic soda		7,139		1,998
NaHS		6,923		3,557
Other		15		196
Total inventories	$	21,544	$	15,988

Our inventory at December 31, 2008 is net of charges totaling $1.2 million that we recorded to reduce the cost basis of our crude oil and petroleum products inventory to reflect market value. The lower of cost or market adjustment is included in “Product Costs” of our Supply & Logistics segment on our consolidated statements of operations. The costs of inventories did not exceed market values at December 31, 2007.

5. Fixed Assets and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following.

	December 31,
	2008			2007
Land, buildings and improvements	$	13,549		$	11,978
Pipelines and related assets		139,184			63,169
Machinery and equipment		22,899			25,097
Transportation equipment		32,833			32,906
Barges and push boats		96,865			—
Office equipment, furniture and fixtures		4,401			2,759
Construction in progress		27,906			7,102
Other		11,575			7,402
Subtotal		349,212			150,413
Accumulated depreciation and impairment		(67,107	)		(48,413	)
Total	$	282,105		$	102,000

In 2008, 2007 and 2006, $276,000, $57,000 and $9,000 of interest cost, respectively, were capitalized related to the construction of pipelines and related assets.

Depreciation expense was $20,415,000, $8,909,000 and $3,719,000 for the years ended December 31, 2008, 2007, and 2006, respectively.

20

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Impairment Charge

During the fourth quarter of 2007, changes in the source of the supply of natural gas to our natural gas gathering pipelines (which are included in our pipeline transportation segment) indicated to us that the carrying amount of our natural gas gathering pipelines might not be recoverable. We made certain assumptions when estimating future cash flows to be generated from the assets including declines in future sales volumes and costs of testing required for integrity purposes. As a result, we tested the carrying value of these assets for recoverability, and determined that we should record an impairment charge of $1,498,000 related to these assets.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with the removal of certain segments of our oil, natural gas and CO₂ pipelines, barge decommissioning, 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.

A reconciliation of our liability for asset retirement obligations is as follows:

Asset retirement obligations as of December 31, 2006	$	708
Liabilities incurred and assumed in the current period		468
Revisions in estimated retirement obligations		(81	)
Accretion expense		78
Asset retirement obligations as of December 31, 2007		1,173
Liabilities incurred and assumed in the current period		121
Accretion expense		136
Asset retirement obligations as of December 31, 2008	$	1,430

At December 31, 2008, $0.2 million of our asset retirement obligation was classified in “Accrued liabilities” under current liabilities in our Consolidated Balance Sheets. Liabilities incurred and assumed during the period are for properties acquired during each year. Certain of our unconsolidated affiliates have asset retirement obligations recorded at December 31, 2008 and 2007 relating to contractual agreements. These amounts are immaterial to our consolidated financial statements.

6. Net Investment in Direct Financing Leases

In the fourth quarter of 2004, we constructed two segments of crude oil pipeline and a CO₂ pipeline segment to transport crude oil from and CO₂ to producing fields operated by Denbury. Denbury pays us a minimum payment each month for the right to use these pipeline segments. Those arrangements have been accounted for as direct financing leases. As discussed in Note 3, we entered into a lease arrangement with Denbury related to the NEJD Pipeline in May 2008 that is being accounted for as a direct financing lease. Denbury pays us fixed payments of $5.2 million per quarter that began in August 2008.

The following table lists the components of the net investment in direct financing leases:

	December 31,
	2008			2007
Total minimum lease payments to be received	$	407,392		$	7,039
Estimated residual values of leased property (unguaranteed)		1,287			1,287
Unamortized initial direct costs		2,580			—
Less unearned income		(230,298	)		(2,953	)
Net investment in direct financing leases	$	180,961		$	5,373

At December 31, 2008, minimum lease payments to be received for each of the five succeeding fiscal years are $21.9 million per year for 2009 through 2011, $21.8 million for 2012 and $21.3 million for 2013.

21

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. CO₂ Assets

CO₂ assets consisted of the following.

	December 31,
	2008			2007
CO2 volumetric production payments	$	43,570		$	43,570
Less - Accumulated amortization		(19,191	)		(14,654	)
Net CO2 assets	$	24,379		$	28,916

The volumetric production payments entitle us to a maximum daily quantity of CO₂ of 101,375 million cubic feet, or Mcf, per day through December 31, 2009, 91,875 Mcf per day for the calendar years 2010 through 2012 and 73,875 Mcf per day beginning in 2013 until we have received all volumes under the production payments. Under the terms of transportation agreements with Denbury, Denbury will process and deliver this CO₂ to our industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary adjustments. During 2008 this fee averaged $0.1927 per Mcf.

The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The seven industrial contracts expire at various dates between 2010 and 2016, with one small contract extending until 2023.

The CO₂ assets are being amortized on a units-of-production method. After purchase price adjustments, we had 276.7 Bcf of CO₂ at acquisition, and the total $43.6 million cost is being amortized based on the volume of CO₂ sold each month. For 2008, 2007 and 2006, we recorded amortization of $4,537,000, $4,488,000 and $4,244,000, respectively. We have 153.8 Bcf of CO₂ remaining under the volumetric production payments at December 31, 2008. Based on the historical deliveries of CO₂ to the customers (which have exceeded minimum take-or-pay volumes), we expect amortization for the next five years to be approximately $4,537,000 from 2009 to 2010, $4,157,000 for 2011 and 2012 and $3,431,000 for 2013.

8. Equity Investees and Other Investments

Equity Investees

We are accounting for our 50% ownership in each of two joint ventures, T&P Syngas and Sandhill under the equity method of accounting. We paid $7.8 million more for our interest in these joint ventures than our share of capital on their balance sheets at the date of the acquisition. This excess amount of the purchase price over the equity in the joint ventures has been allocated to the tangible and intangible assets of the joint ventures based on the fair value of those assets, with the remainder of the excess purchase price of $0.7 million allocated to goodwill. The table below reflects information included in our consolidated financial statements related to our equity investees.

	Year Ended December 31,
	2008			2007			2006
Genesis’ share of operating earnings		1,137			1,898			1,690
Amortization of excess purchase price		(628	)		(628	)		(559	)
Net equity in earnings	$	509		$	1,270		$	1,131
Distributions received	$	2,158		$	2,240		$	2,093

Other Projects

We have also invested $4.6 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.

22

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

No events or changes in circumstances have occurred that indicate a significant adverse effect on the fair value of our investment at December 31, 2008, therefore the investment is included in our consolidated balance sheet at cost.

9. Intangible Assets, Goodwill and Other Assets

Intangible Assets

In connection with the Davison and DG Marine acquisitions (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 December 31, 2008:

		December 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	5	$	94,654	$	26,017	$	68,637	$	94,654	$	9,380	$	85,274
Supply and logistics customer relationships	5		35,430		9,957		25,473		34,630		3,287		31,343
Refinery services supplier relationships	2		36,469		24,483		11,986		36,469		9,241		27,228
Refinery services licensing agreements	6		38,678		7,176		31,502		38,678		2,218		36,460
Supply and logistics trade names - Davison and Grifco	7		18,888		3,118		15,770		17,988		930		17,058
Supply and logistics favorable lease	15		13,260		671		12,589		13,260		197		13,063
Other	5		1,322		346		976		721		97		624
Total	5	$	238,701	$	71,768	$	166,933	$	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 names are the Davison and Grifco names, 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 $46.4 million and $25.4 million for the years ended December 31, 2008 and 2007, respectively.

The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:

	2009		2010		2011		2012		2013
Refinery services customer relationships	$	15,433	$	11,689	$	8,972	$	7,056	$	7,116
Supply and logistics customer relationships		5,536		4,488		3,603		2,819		2,165
Refinery services supplier relationships		4,068		2,925		2,629		2,364		—
Refinery services licensing agreements		4,505		4,105		3,690		3,416		3,163
Supply and logistics trade name		2,326		2,086		1,851		1,432		1,237
Supply and logistics favorable lease		474		474		474		474		474
Other		285		187		53		54		56
Total	$	32,627	$	25,954	$	21,272	$	17,615	$	14,211

23

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Goodwill

The carrying amount of goodwill by business segment at December 31, 2008 and 2007 was as follows:

	Refinery Services		Supply & Logistics		Total
2007 Additions:
Davison acquisition	$	297,621	$	19,118	$	316,739
Port Hudson Assets Acquisition		—		3,969		3,969
Balance, December 31, 2007		297,621		23,087		320,708
Davison acquisition, due to purchase price adjustments		4,338		—		4,338
December 31, 2008	$	301,959	$	23,087	$	325,046

We performed our annual goodwill impairment test pursuant to SFAS 142 on October 1, 2008. The fair value of our supply and logistics and refinery services reporting units were estimated using a combined income (discounted cash flow) and market approach (guideline public company and comparable merged and acquired transactions) valuation method which indicated that the fair value of our net assets in each reporting unit exceeded the carrying value of that reporting unit, and an impairment charge was not required. The estimated fair value of our reporting units is dependent on several significant assumptions and estimates, including our growth rates for revenues and costs, changes in operating margins, future capital expenditures related to our existing operations, our cost of capital (discount rate) and cash flow market multiples. Our business plans and recent operating results also impact our estimate of the fair value of our reporting units.

SFAS 142 requires the performance of an interim goodwill impairment test if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Due to the ongoing deterioration of the credit markets and the overall macroeconomic conditions existing at December 31, 2008, we evaluated our fourth quarter performance and the outlook for our business segments, also considering the decline in our market capitalization, and concluded that we did not have a triggering event in the fourth quarter that would require the performance of an interim goodwill impairment test.

We will continue to monitor the general economic conditions, our operational and financial performance measures and our market capitalization to determine if a triggering event occurs and will perform an interim goodwill impairment analysis, if necessary. We have not recognized any impairment losses related to goodwill for any of the periods presented.

Other Assets

Other assets consisted of the following.

	December 31,
	2008			2007
Credit facility fees - Genesis	$	5,022		$	5,022
Credit facility fees - DG Marine		2,536			—
Initial direct costs related to Free State Pipeline lease		1,132			—
Deferred tax asset		1,543			941
Other deferred costs and deposits		7,502			3,284
		17,735			9,247
Less - Accumulated amortization		(2,322	)		(850	)
Net other assets	$	15,413		$	8,397

Amortization of the initial direct costs related to the Free State Pipeline lease for the year ended December 31, 2008 was $35,000. Amortization expense of credit facility fees for the years ended December 31, 2008, 2007 and 2006 was $1,437,000, $779,000 and $394,000, respectively. In the fourth quarter of 2006, we also charged to expense $575,000 of unamortized fees related to the facility that we replaced in November 2006. Total amortization of initial direct costs and credit facility fees for the next five years will be $1,993,000 for 2009 and 2010, $1,465,000 in 2011 and $60,000 in 2012 and 2013.

24

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Debt

At December 31, 2008 our obligations under credit facilities consisted of the following:

	December 31, 2008		December 31, 2007
Genesis Credit Facility	$	320,000	$	80,000
DG Marine Credit Facility (non-recourse to Genesis)		55,300		—
Total Long-Term Debt	$	375,300	$	80,000

Genesis Credit Facility

We have a $500 million credit facility $100 million of which can be used for letters of credit, with a group of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc. 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 December 31, 2008 exceeds $500 million.

At December 31, 2008, we had $320 million borrowed under our credit facility and we had $3.5 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 December 31, 2008 was $176.5 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 December 31, 2008, our borrowing rates were the prime rate plus 0.50% or the LIBOR rate plus 1.50%.

• 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 December 31, 2008, our letter of credit rate was 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 December 31, 2008, the commitment fee rate was 0.30%.

Collateral under the credit facility consists of substantially all our assets, excluding our interest in the NEJD pipeline, our ownership interest in the Free State pipeline, and the assets of and our equity interest in, DG Marine. All of the equity interest of DG Marine is pledged to secure its credit facility, which is described below. 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.

25

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Covenant	Requirement	Required Ratio through December 31, 2008	Actual Ratio as of December 31, 2008
Debt Service Coverage Ratio	Minimum	2.75 to 1.0	8.53 to 1.0
Leverage Ratio	Maximum	6.0 to 1.0	2.82 to 1.0
Funded Indebtedness Ratio	Maximum	0.80 to 1.0	0.39 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 (as defined in the credit facility) generated by us for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. At December 31, 2008, the excess of distributable cash over distributions under this provision of the credit facility was $49.7 million.

DG Marine Credit Facility

In connection with its acquisition of the Grifco assets on July 18, 2008, DG Marine entered into a $90 million revolving credit facility with a syndicate of banks led by SunTrust Bank and BMO Capital Markets Financing, Inc. In addition to partially financing the Grifco acquisition, DG Marine may borrow under that facility for general corporate purposes, such as paying for its newly constructed barges and funding working capital requirements, including up to $5 million in letters of credit. That facility, which matures on July 18, 2011, is secured by all of the equity interests issued by DG Marine and substantially all of DG Marine’s assets. Other than the pledge of our equity interest in DG Marine and our guaranty of $7.5 million, that facility is non-recourse to us and TD Marine. At December 31, 2008, our consolidated balance sheet included $115.8 million of DG Marine’s assets in our total assets.

At December 31, 2008, DG Marine had $55.3 million outstanding under its credit facility. Due to the revolving nature of loans under the DG Marine credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings at December 31, 2008 was $34.7 million under this credit facility.

The key terms for rates under the DG Marine 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 1.50% to the prime rate plus 4.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.50% to the LIBOR rate plus 5.00%. The rate is based on DG Marine’s leverage ratio as computed under the credit facility. Under the terms of DG Marine’s credit facility, the rates will fluctuate quarterly based on the leverage ratio. At December 31, 2008, DG Marine’s borrowing rates were the prime rate plus 4.00% or the LIBOR rate plus 5.00%.

• Letter of credit fees will range from 2.50% to 5.00% based on DG Marine’s leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2008, there were no letters of credit outstanding under the DG Marine credit facility.

• DG Marine pays a commitment fee on the unused portion of the $90 million facility amount. The commitment fee will range from 0.25% to 0.50% based on its leverage ratio as computed under the credit facility. The rate will fluctuate quarterly based on the leverage ratio. At December 31, 2008, the commitment fee rate was 0.50%.

In August 2008, DG Marine entered into a series of interest rate swap agreements to effectively fix the underlying LIBOR rate on $32.9 million of its borrowings under its credit facility through July 18, 2011. The fixed interest rates in the swap agreements range from the three-month interest rate of 3.20% in effect at December 31, 2008 to 4.68% at July 18, 2011.

26

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DG Marine’s credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which it may conduct its business. DG Marine’s credit facility contains three primary financial covenants – an interest coverage ratio, leverage ratio and asset coverage ratio – that require DG Marine to achieve specific minimum financial metrics. In general, the interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense. The leverage ratio calculation compares DG Marine’s funded debt (as calculated in accordance with the credit facility) to EBITDA (as adjusted). The asset coverage ratio compares an estimated liquidation value of DG Marine’s boats and barges to DG Marine’s outstanding debt.

Maturities of long-term debt in the next five years, including the DG Marine credit facility, are $375.3 million in 2011. We have estimated the fair value of our long-term debt to be approximately $358.4 million, or $16.9 million less than the carrying value of that debt based on consideration of our credit standing.

11. Partners’ Capital and Distributions

Partner’s capital at December 31, 2008 consists of 39,456,774 common units, including 4,028,096 units owned by our general partner and its affiliates, 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.

Our general partner owns all of our general partner interest, including incentive distribution rights (IDRs), all of the 0.01% general partner interest in Genesis Crude Oil, L.P. (which is reflected as a noncontrolling interest in the Consolidated Balance Sheet at December 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 10, our credit facility limits the amount of distributions we may pay in any quarter. At December 31, 2008, our restricted net assets (as defined in Rule 4-03(e)(3) of Regulations S-X) were $573.6 million.

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:

	Unitholders		General 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	%	25.47	%
Over Second Target - Cash distributions greater than $.033 per Unit	49.02	%	50.98	%

27

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We paid distributions in 2007 and 2008 as follows:

Distribution For	Date Paid	Per Unit Amount		Limited Partner Interests Amount			General Partner Interest Amount		General Partner Incentive Distribution Amount		Total Amount
Fourth quarter 2006	February 2007	$	0.2100	$	2,895		$	59	$	—	$	2,954
First quarter 2007	May 2007	$	0.2200	$	3,032		$	62	$	—	$	3,094
Second quarter 2007	August 2007	$	0.2300	$	3,170	(1)	$	65	$	—	$	3,235	(1)
Third quarter 2007	November 2007	$	0.2700	$	7,646		$	156	$	90	$	7,892
Fourth quarter 2007	February 2008	$	0.2850	$	10,902		$	222	$	245	$	11,369
First quarter 2008	May 2008	$	0.3000	$	11,476		$	234	$	429	$	12,139
Second quarter 2008	August 2008	$	0.3150	$	12,427		$	254	$	633	$	13,314
Third quarter 2008	November 2008	$	0.3225	$	12,723		$	260	$	728	$	13,711
Fourth quarter 2008	February 2009	$	0.3300	$	13,021		$	266	$	823	$	14,110

(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.

28

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Income (Loss) per Common Unit

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

	Year Ended December 31,
	2008			2007			2006
Numerators for basic and diluted net income (loss) per common unit:
Income (loss) attributable to Genesis Energy, L.P. before cumulative effect adjustment	$	26,089		$	(13,550	)	$	8,351
Less: General partner’s incentive distribution to to be paid for the period		(2,613	)		(335	)		—
Subtotal		23,476			(13,885	)		8,351
Less: General partner 2% ownership		(470	)		277			(167	)
Income (loss) before cumulative effect adjustment available for common unitholders	$	23,006		$	(13,608	)	$	8,184
Income from cumulative effect adjustment	$	—		$	—		$	30
Less: General partner 2% ownership		—			—			—
Income from cumulative effect adjustment available for common unitholders	$	—		$	—		$	30
Denominator for basic per common unit:
Common Units		38,961			20,754			13,784
Denominator for diluted per common unit:
Common Units		38,961			20,754			13,784
Phantom Units		64			—			—
		39,025			20,754			13,784
Basic net income per common unit	$	0.59		$	(0.66	)	$	0.59
Diluted net income per common unit	$	0.59		$	(0.66	)	$	0.59

Equity Issuances and Contributions

During the last three years we have issued a total of 15,495,940 common units in the acquisition of assets. A summary of these unit issuances is as follows:

Period	Acquisition Transaction	Units	Value Attributed to Assets
July 2008	Grifco	838	$	16,667
May 2008	Free State Pipeline	1,199	$	25,000
July 2007	Davison	13,459	$	330,000

We issued new common units to the public and our general partner for cash as follows:

Period	Purchaser of Common Units	Units	Gross Unit Price		Issuance Value		GP Contributions		Costs		Net Proceeds
December 2007	Public	9,200	$	22.000	$	202,400	$	—	$	8,846	$	193,554
December 2007	General Partner	735	$	21.120	$	15,518	$	4,447	$	—	$	19,965
July 2007	General Partner	1,075	$	20.836	$	22,361	$	6,171	$	—	$	28,532

29

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On July 18, 2008, we issued 837,690 of our common units to Grifco. The units were issued at a value of $19.896 per unit, for a total value of $16.7 million, as a portion of the consideration for the acquisition of the inland marine transportation business of Grifco.

Additionally, on July 18, 2008, we redeemed 837,690 of our common units owned by members of the Davison family. Those units had been issued as a portion of the consideration for the acquisition of the energy-related business of the Davison family in July 2007. The redemption was at a value of $19.896 per unit, for a total value of $16.7 million. After giving effect to the issuance and redemption described above, we did not experience a change in the number of common units outstanding

On May 30, 2008, we issued 1,199,041 common units to Denbury in connection with the acquisition of the Free State pipeline. Our general partner also contributed $0.5 million to maintain its capital account balance.

On December 10, 2007 we issued 9,200,000 common units is a public offering, providing cash of $193.6 million after underwriters discount and offering costs. Our general partner exercised its right to maintain its proportionate share of our outstanding units and purchased 734,732 common units from us for $15.5 million, or $21.12 per common unit. Our general partner also contributed approximately $4.4 million to maintain its capital account balance.

In July 2007, we issued 13,459,209 common units to the entities owned and controlled by the Davison family as a portion of the purchase price. Additionally at that time, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit. As required under our partnership agreement, our general partner also contributed approximately $6.2 million to maintain its capital account balance.

Our general partner made a capital contribution of $1.4 million in December 2007 to offset a portion of the severance payment to a former executive. We also recorded a non-cash capital contribution of $3.4 million from our general partner for the estimated value of the compensation earned in 2007 under the proposed arrangements with our senior management team related to an incentive interest in our general partner. As the purpose of incentive interest is to incentivize these individuals to grow the partnership, the expense is recognized as compensation by us and a capital contribution by the general partner.

12. 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 and barge crude oil and petroleum products. All of our revenues are derived from, and all of our assets are located in the United States.

During the fourth quarter of 2008, we revised the manner in which we internally evaluate our segment performance. As a result, we changed our definition of segment margin to include within segment margin all costs that are directly associated with the business segment. Segment margin now includes costs such as general and administrative expenses that are directly incurred by the business segment. Segment margin also includes all payments received under direct financing leases. In order to improve comparability between periods, we exclude from segment margin the non-cash effects of our stock-based compensation plans which are impacted by changes in the market price for our common units. Previous periods have been restated to conform to this segment presentation. We now define segment margin as revenues less cost of sales, operating expenses (excluding depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures. Our segment margin definition also excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases. 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.

30

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Pipeline Transportation		Refinery Services				Industrial Gases (a)		Supply & Logistics			Total
Year Ended December 31, 2008
Segment margin excluding depreciation and amortization(b)	$	33,149	$	55,784			$	13,504	$	32,448		$	134,885
Capital expenditures(c)	$	262,200	$	5,490			$	2,397	$	118,585		$	388,672
Maintenance capital expenditures	$	719	$	1,881		��	$	—	$	1,854		$	4,454
Net fixed and other long-term assets(d)	$	285,773	$	434,956			$	44,003	$	245,815		$	1,010,547
Revenues:
External customers	$	39,051	$	233,871			$	17,649	$	1,851,113		$	2,141,684
Intersegment(e)		7,196		(8,497	)			—		1,301			—
Total revenues of reportable segments	$	46,247	$	225,374			$	17,649	$	1,852,414		$	2,141,684
Year Ended December 31, 2007
Segment margin excluding depreciation and amortization(b)	$	14,170	$	19,713			$	13,038	$	10,646		$	57,567
Capital expenditures(c)	$	6,592	$	503,765			$	1,104	$	138,403		$	649,864
Maintenance capital expenditures	$	2,880	$	469			$	—	$	491		$	3,840
Net fixed and other long-term assets(d)	$	32,936	$	468,068			$	47,364	$	145,915		$	694,283
Revenues:
External customers	$	23,226	$	62,095			$	16,158	$	1,098,174		$	1,199,653
Intersegment(e)		3,985						—		(3,985	)		—
Total revenues of reportable segments	$	27,211	$	62,095			$	16,158	$	1,094,189		$	1,199,653
Year Ended December 31, 2006
Segment margin excluding depreciation and amortization(b)	$	13,280	$	—			$	12,844	$	5,017		$	31,141
Capital expenditures(c)	$	971	$	—			$	6,058	$	356		$	7,385
Maintenance capital expenditures	$	611	$	—			$	—	$	356		$	967
Net fixed and other long-term assets(d)	$	31,863	$	—			$	51,630	$	7,602		$	91,095
Revenues:
External customers	$	25,479	$	—			$	15,154	$	877,736		$	918,369
Intersegment(e)		4,468		—				—		(4,468	)		—
Total revenues of reportable segments	$	29,947	$	—			$	15,154	$	873,268		$	918,369

31

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(a) The industrial gases segment includes our CO₂ marketing operations and the income from our investments in T&P Syngas and Sandhill.

(b) A reconciliation of segment margin to income before income taxes for each year presented is as follows:

	Year Ended December 31,
	2008			2007			2006
Segment margin excluding depreciation and amortization	$	134,885		$	57,567		$	31,141
Corporate general and administrative expenses		(22,113	)		(17,573	)		(10,238	)
Depreciation and amortization		(71,370	)		(40,245	)		(7,963	)
Net (loss) gain on disposal of surplus assets		(29	)		(266	)		16
Interest expense, net		(12,937	)		(10,100	)		(1,374	)
Non-cash expenses not included in segment margin		1,206			(1,855	)		(1,343	)
Other non-cash items affecting segment margin		(4,179	)		(1,733	)		(1,898	)
Income (loss) before income taxes	$	25,463		$	(14,205	)	$	8,341

(c) Capital expenditures includes fixed asset additions and acquisitions of businesses.

(d) Net fixed and other long-term assets is a measure used by management in evaluating the results of our operations on a segment basis. Current assets are not allocated to segments as the amounts are not meaningful in evaluating the success of the segment’s operations. Amounts for our Industrial Gases segment include investments in equity investees totaling $14.5 million, $16.2 million and $17.2 million at December 31, 2008, 2007 and 2006, respectively.

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

13. 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.

32

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2008		2007		2006
Truck transportation services provided to Denbury	$	3,578	$	1,791	$	825
Pipeline transportation services provided to Denbury	$	10,727	$	5,290	$	4,228
Payments received under direct financing leases from Denbury	$	11,519	$	1,188	$	1,186
Pipeline transportation income portion of direct financing lease fees	$	11,011	$	641	$	655
Pipeline monitoring services provided to Denbury	$	120	$	120	$	65
Directors’ fees paid to Denbury	$	195	$	150	$	120
CO2 transportation services provided by Denbury	$	6,424	$	5,213	$	4,640
Crude oil purchases from Denbury	$	—	$	101	$	1,565
Operations, general and administrative services provided by our general partner	$	51,872	$	22,490	$	16,777
Distributions to our general partner on its limited partner units and general partner interest, including incentive distributions	$	6,463	$	1,671	$	963
Sales of CO2 to Sandhill (for the period since Sandhill became a related party)	$	2,941	$	2,783	$	2,056
Petroleum products sales to Davison family businesses	$	1,261	$	—	$	—
Transition services costs to Davison family	$	—	$	9,880	$	—

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 earned fees from Denbury for the transportation of their CO₂ on our Free State pipeline. We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven and NEJD CO₂ pipelines 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 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 and for attendance at meetings that are the same as the rates 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 2008, the inflation-adjusted transportation fee averaged $0.1927 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, excluding any payments to our management team pursuant to their Class B Membership Interests. See Note 15.

33

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amounts due to and from Related Parties

At December 31, 2008 and 2007, we owed Denbury $1.0 million, respectively, for CO₂ transportation charges. Denbury owed us $2.0 million and $0.9 million for transportation services at December 31, 2008 and 2007, respectively. We owed our general partner $2.1 million and $0.7 million for administrative services at December 31, 2008 and 2007, respectively. At December 31, 2008 and 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.

Drop-down transactions

On May 30, 2008, we entered into a $175 million financing lease arrangement with Denbury Onshore for its NEJD Pipeline System, and acquired its Free State CO₂ pipeline system for $75 million, consisting of $50 million cash and $25 million of our common units. See Note 3.

Unit redemption

As discussed in Note 11, we redeemed 837,690 of our common units owned by members of the Davison family. The total value of the units redeemed was $16.7 million.

DG Marine joint venture

Our partner in the DG Marine joint venture is TD Marine, LLC, a joint venture consisting of three members of the Davison family. See Note 3.

Financing

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 Genesis Crude Oil, L.P. 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.

We guarantee 50% of the obligation of Sandhill to a bank. At December 31, 2008, the total amount of Sandhill’s obligation to the bank was $3.0 million; therefore, our guarantee was for $1.5 million.

Approximately 14% of the outstanding common shares of Community Trust Bank are held by Davison family members. Community Trust Bank is a 17% participant in the DG Marine credit facility. James E. Davison, Jr., a member of our board of directors, also serves on the board of the holding company that owns Community Trust Bank.

As discussed in Note 11, our general partner made capital contributions in order to maintain its capital account totaling $0.5 million and $10.6 million in 2008 and 2007, respectively. Our general partner also purchased common units totaling $37.9 million in 2007. In addition, our general partner made a capital contribution of $1.4 million in December 2007 to offset a portion of the severance payment to a former executive. In 2007, we recorded a capital contribution from our general partner of $3.4 million related to compensation recognized for our executive management team. See Note 15.

In December 2008, our general partner established Class B Membership Interests in our general partner to be used as long-term incentive compensation for our senior executives. See Note 15.

14. Supplemental Cash Flow Information

The following table provides information regarding the net changes in components of operating assets and liabilities.

34

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2008			2007			2006
Decrease (increase) in:
Accounts receivable	$	61,126		$	(35,362	)	$	(6,472	)
Inventories		(5,557	)		(143	)		(4,664	)
Other current assets		(2,419	)		(1,887	)		870
Increase (decrease) in:
Accounts payable		(58,224	)		34,523			1,359
Accrued liabilities		3,812			6,149			34
Net changes in components of operating assets and liabilities, net of working capital acquired	$	(1,262	)	$	3,280		$	(8,873	)

Cash received by us for interest during the years ended December 31, 2008, 2007 and 2006 was $0.1 million, $0.3 million and $0.2 million, respectively. Payments of interest and commitment fees were $11.3 million, $8.4 million and $1.0 million, during the years ended December 31, 2008, 2007 and 2006, respectively.

Cash paid for income taxes in during the years ended December 31, 2008 and 2007 was $2.4 million and $1.6 million, respectively.

At December 31, 2008 and 2007, we had incurred liabilities for fixed asset additions totaling $1.7 million and $0.9 million, respectively, that had not been paid at the end of the year and, therefore, are not included in the caption “Additions to property and equipment” on the Consolidated Statements of Cash Flows. We had incurred liabilities for other assets totaling $0.3 million at December 31, 2007 that had not been paid at the end of the year and, therefore, are not included in the caption “Other, net” under investing activities on the Consolidated Statements of Cash Flows.

In May 2008, we issued common units with a value of $25 million as part of the consideration for the acquisition of the Free State Pipeline from Denbury. In July 2008, we issued common units with a value of $16.7 million as part of the consideration for the acquisition of the inland marine transportation assets of Grifco. These common unit issuances are non-cash transactions and the value of the assets acquired is not included in investing activities and the issuance of the common units is not reflected under financing activities in our Consolidated Statements of Cash Flows. Additionally, we deferred payment of $12 million ($11.7 million discounted) of the consideration in the acquisition from Grifco to December 2008 and 2009. This deferral of the payment of consideration was a non-cash transaction and the value of the assets acquired is not included in investing activities and the payments due in December 2009 is not reflected under financing activities in our Consolidated Statements of Cash Flows. The subsequent payment in December 2008 of one-half of the consideration is included in financing cash flows.

In July 2007, we issued common units with a value of $330 million as part of the consideration in the Davison acquisition. This common unit issuance is a non-cash transaction and the value of the assets acquired is not included under investing activities and the issuance of the common units are not reflected under financing activities in our Consolidated Statements of Cash Flows.

In 2007, our general partner made a non-cash contribution to us in the amount of $3.4 million that is not included in financing activities in the Consolidated Statements of Cash Flows. This contribution related to the estimated compensation earned by our management team for its services in 2007 under the proposed compensation arrangement with these individuals that existed at December 31, 2007.

15. Employee Benefit Plans and Equity-Based Compensation Plans

We do not directly employ any of the persons responsible for managing or operating our activities. Employees of our general partner provide those services and are covered by various retirement and other benefit plans.

In order to encourage long-term savings and to provide additional funds for retirement to its employees, our general partner sponsors a profit-sharing and retirement savings plan. Under this plan, our general partner’s matching contribution is calculated as an equal match of the first 3% of each employee’s annual pretax contribution and 50% of the next 3% of each employee’s annual pretax contribution. Our general partner also made a profit-sharing contribution of 3% of each eligible employee’s total compensation (subject to IRS limitations). The expenses included in the consolidated statements of operations for costs relating to this plan were $2.2 million, $0.8 million, and $0.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

35

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our general partner also provided certain health care and survivor benefits for its active employees. Our health care benefit programs are self-insured, with a catastrophic insurance policy to limit our costs. Our general partner plans to continue self-insuring these plans in the future. The expenses included in the consolidated statements of operations for these benefits were $1.7 million, $1.5 million, and $1.3 million in 2008, 2007 and 2006, respectively. Effective January 1, 2008, the employees who operate the assets we acquired from the Davison family became participants in these plans.

Stock Appreciation Rights Plan

Under the terms of our stock appreciation rights plan, regular, full-time active employees (with the exception of our chief executive officer, chief operating officer and chief financial officer) and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, who shall receive awards under the plan, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one common unit.

The rights have a term of 10 years from the date of grant. If the right has not been exercised at the end of the ten year term and the participant has not terminated his employment with us, the right will be deemed exercised as of the date of the right’s expiration and a cash payment will be made as described below.

Upon vesting, the participant may exercise his rights and receive a cash payment calculated as the difference between the averages of the closing market price of our common units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date.

Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested.

The compensation cost associated with our stock appreciation rights plan, which upon exercise will result in the payment of cash to the employee, is re-measured each reporting period based on the fair value of the rights. Under SFAS No. 123 (revised December 2004), “Share-Based Payments.”, the liability is calculated using a fair value method that takes into consideration the expected future value of the rights at their expected exercise dates.

We have elected to calculate the fair value of the rights under the plan using the Black-Scholes valuation model. This model requires that we include the expected volatility of the market price for our common units, the current price of our common units, the exercise price of the rights, the expected life of the rights, the current risk free interest rate, and our expected annual distribution yield. This valuation is then applied to the vested rights outstanding and to the non-vested rights based on the percentage of the service period that has elapsed. The valuation is adjusted for expected forfeitures of rights (due to terminations before vesting, or expirations after vesting). The liability amount accrued on the balance sheet is adjusted to this amount at each balance sheet date with the adjustment reflected in the statement of operations.

The estimates that we make each period to determine the fair value of these rights include the following assumptions:

Assumptions Used for Fair Value of Rights

	December 31, 2008	December 31, 2007	December 31, 2006
Expected life of rights (in years)	1.25 - 6.00	2.25 - 6.25	3.25 - 7.00
Risk-free interest rate	0.57% - 1.71%	3.12% - 3.65%	4.53% - 4.57%
Expected unit price volatility	42.8%	34.2%	32.1%
Expected future distribution yield	6.00%	6.00%	6.00%

36

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• In determining the expected life of the rights, we use the simplified method allowed by the Securities and Exchange Commission. As our stock appreciation rights plan was not put in place until December 31, 2003, we have very limited experience with employee exercise patterns.

• The expected volatility of our units is computed using the historical period we believe is representative of future expectations. We determined the period to use as the historical period by considering our distribution history and distribution yield.

• The risk-free interest rate was determined from the current yield for U.S. Treasury zero-coupon bonds with a term similar to the remaining expected life of the rights.

• In determining our expected future distribution yield, we considered our history of distribution payments, our expectations for future payments, and the distribution yields of entities similar to us. While current market conditions result in a higher distribution yield, we believe that the yield will be closer to 6% over the life of the outstanding rights.

• We estimated the expected forfeitures of non-vested rights and expirations of vested rights. We have very limited experience with employee forfeiture and expiration patterns, as our plan was not initiated until December 31, 2003. We reviewed the history available to us as well as employee turnover patterns in determining the rates to use. We also used different estimates for different groups of employees.

The following table reflects rights activity under our plan as of January 1, 2008, and changes during the year ended December 31, 2008:

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 during 2008	536,308		$	20.83
Exercised during 2008	(38,995	)	$	19.52
Forfeited or expired during 2008	(72,786	)	$	21.23
Outstanding at December 31, 2008	1,017,985		$	18.09	7.9	$	—
Exercisable at December 31, 2008	381,016		$	14.82	6.2	$	—

The weighted-average fair value at December 31, 2008 of rights granted during 2008 was $0.67 per right, determined using the following assumptions:

Assumptions Used for Fair Value of Rights

Granted in 2008

Expected life of rights (in years)	5.25 - 6.00
Risk-free interest rate	1.57% - 1.71%
Expected unit price volatility	42.8%
Expected future distribution yield	6.00%

The total intrinsic value of rights exercised during 2008, 2007 and 2006 was $0.4 million, $1.6 million and $0.4 million, respectively, which was paid in cash to the participants.

At December 31, 2008, there was $0.2 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 December 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 date until the rights are exercised, forfeited or expire. For the awards outstanding at December 31, 2008, the remaining cost will be recognized over a weighted average period of approximately one year.

37

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We recorded charges and credits related to our stock appreciation rights for three years ended December 31, 2008 as follows:

Expense (Credits to Expense) Related to Stock Appreciation Rights

Statement of Operations	2008			2007		2006
Supply and logistics operating costs	$	(997	)	$	528	$	362
Refinery services operating costs		23			—		—
Pipeline operating costs		(296	)		420		289
General and administrative expenses		(1,141	)		1,576		1,279
Total	$	(2,411	)	$	2,524	$	1,930

2007 Long Term Incentive Plan

Our Genesis Energy, Inc. 2007 Long Term Incentive Plan (the “2007 LTIP”) provides for awards of Phantom Units and Distribution Equivalent Rights to non-employee directors and employees of Genesis Energy, LLC, our general partner. Phantom Units are notional units representing unfunded and unsecured promises to deliver a Partnership common unit to the participant should specified vesting requirements be met. Distribution Equivalent Rights are rights to receive an amount of cash equal to all or a portion of the cash distributions made by the Partnership during a specified period. The 2007 LTIP is administered by the Compensation Committee of the board of directors of our general partner (the “Board”).

The Compensation Committee (at its discretion) will designate participants in the 2007 LTIP, determine the types of awards to grant to participants, determine the number of units to be covered by any award, and determine the conditions and terms of any award including vesting, settlement and forfeiture conditions. The 2007 LTIP may be amended or terminated at any time by the Board or the Compensation Committee; however, any material amendment, such as a material increase in the number of units available under the 2007 LTIP or a change in the types of awards available under the 2007 LTIP, will also require the approval of our unitholders. The Compensation Committee is also authorized to make adjustments in the terms and conditions of and the criteria included in awards under the plan in specified circumstances.

The common units to be awarded under the 2007 Plan will be obtained by our general partner through purchases made on the open market, from us, from any affiliates of our general partner or from any other person; however, it is generally intended that units are to be acquired from us as newly-issued common units.

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 915,429 remain authorized for issuance at December 31, 2008. Compensation expense is recognized on a straight-line basis over the vesting period. The fair value of the units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures. Due to the positions of the small group of employees and non-employee directors who received these grants, we have assumed that there will be no forfeitures of these Phantom Units in our fair value calculation as of December 31, 2008. The grant date fair value of the awards are measured by reducing the grant date market price by the present value of the distributions expected to be paid on the shares during the requisite service period, discounted at an appropriate risk-free interest rate.

The aggregate grant date fair value of Phantom Unit awards granted during 2008 and 2007 was $0.8 million and $0.9 million, respectively. The total fair value of Phantom Units that vested during the year ended December 31, 2008 was $0.1 million. Compensation expense recognized during 2008 for Phantom Units was $0.7 million. Expense recorded during 2007 was less than $0.1 million. As of December 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 one year.

38

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Non-vested Phantom Unit Grants	Number of  Units		Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2007	—
Granted during 2007	39,362		$	21.92
Non-vested at December 31, 2007	39,362		$	21.92
Granted during 2008	45,209		$	17.63
Vested during 2008	(6,183	)	$	23.46
Non-vested at December 31, 2008	78,388		$	19.32

The weighted-average fair value of Phantom Units granted during 2007 and 2008 was determined using the following assumptions:

Year Granted	Grant Date Price	Expected Distribution Rate	Risk Free Rate
2007	$24.52	$0.27	3.19% - 3.31%
2008	$15.50 - $21.30	$0.285 - $0.315	2.01% - 2.40%

Bonus Program

In January 2009, the Committee of the Board of our general partner approved a bonus program (referred to below as the Bonus Plan) for all employees of our general partner (with the exception of our Chief Executive Officer, Chief Operating Officer and Chief Financial Officer (collectively our “Senior Executives”)) that was applicable to 2008. The Bonus Plan is paid at the discretion of our Board based on the recommendation of the Compensation Committee, and can be amended or changed at any time. The Bonus Plan is designed to enhance the financial performance of the Partnership by rewarding employees for achieving financial performance and safety objectives. While the maximum amount that will be paid each year as bonuses is calculated based on two metrics, the actual amounts paid individually are discretionary and may total to less than the maximum that might otherwise be available.

The Bonus Plan is based primarily on the amount of money we generate for distributions to our unitholders, and is measured on a calendar-year basis. For 2008, two metrics were used to determine the bonus pool – the level of Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generate and our company-wide safety record improvement. The level of Available Cash before Reserves generated for the year as a percentage of a target set by our Committee is weighted ninety percent and the achieved level of the targeted improvement in our safety record is weighted ten percent. The sum of the weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages established by our Compensation Committee for the various levels of our employees to determine the maximum bonus pool from which the majority of our employees are paid bonuses.

A separate marketing bonus pool is available for compensating certain marketing personnel that is based on the contribution of that marketing group to Available Cash before Reserves. A minimum level of contribution to Available Cash before Reserves is required before any amounts are allocated to the marketing bonus pool.

For 2008, we accrued $4.0 million for the general bonus pool and $0.5 million for the marketing bonus pool in 2008. These bonuses were paid to employees in March 2009. In 2007 and 2006, we accrued $2.0 million and $1.8 million for bonuses under previous bonus arrangements.

Severance Protection Plan

In June 2005, the Compensation Committee of the Board of Directors of our general partner approved the Genesis Energy Severance Protection Plan, or Severance Plan, for employees of our general partner (with the exception of the new senior management team.) The Severance Plan provides that a participant in the Plan is entitled to receive a severance benefit if his employment is terminated during the period beginning six months prior to a change in control and ending two years after a change in control, for any reason other than (x) termination by our general partner for cause or (y) termination by the participant for other than good reason. Termination by the participant for other than good reason would be triggered by a change in job status, a reduction in pay, or a requirement to relocate more than 25 miles.

39

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A change in control is defined in the Severance Plan. Generally, a change in control is a change in the control of Denbury, a disposition by Denbury of more than 50% of our general partner, or a transaction involving the disposition of substantially all of the assets of Genesis.

The amount of severance is determined separately for three classes of participants. The first class, which includes two Executive Officers of Genesis, would receive a severance benefit equal to three times that participant’s annual salary and bonus amounts. The second class, which includes certain other members of management, would receive a severance benefit equal to two times that participant’s salary and bonus amounts. The third class of participant would receive a severance benefit based on the participant’s salary and bonus amounts and length of service. Participants would also receive certain medical and dental benefits.

Class B Membership Interests

As part of finalizing the compensation arrangements for our Senior Executives on December 31, 2008, our general partner awarded them an equity interest in our general partner as long-term incentive compensation. These Class B Membership Interests compensate the holders thereof by providing rewards based on increased shares of the cash distributions attributable to our incentive distribution rights (or IDRs)(See Note 11) to the extent we increase Cash Available Before Reserves, or CABR (defined below) (from which we pay distributions on our common units) above specified targets. CABR generally means Available Cash before Reserves, less Available Cash before Reserves generated from specific transactions with our general partner and its affiliates (including Denbury Resources Inc.) The Class B Membership Interests do not provide any Senior Executive with a direct interest in any assets (including our IDRs) owned by our general partner. During his employment with our general partner, each Senior Executive will be entitled to receive quarterly distributions in respect of his Class B Membership Interest from our general partner in amounts equal to a percentage of the distributions we pay in respect of our IDRs. Each Senior Executive’s quarterly distribution percentage of our IDRs may vary from quarter-to-quarter based on a formula included in the agreements. In addition, upon the occurrence of specified events and circumstances, our general partner will redeem a Senior Executive’s Class B Membership Interest when that executive’s employment with our general partner is terminated or when a change of control occurs. Additionally our chief executive officer and chief operating officer participate in a deferred compensation plan, whereby they may be entitled to receive a cash payment upon termination of employment.

Our general partner has agreed that it will not seek reimbursement (on behalf of itself or its affiliates) under our partnership agreement for the costs of these Senior Executive compensation arrangements to the extent relating to their ownership of Class B Membership Interests (including current cash distributions made by the general partner out of its IDRs and payment of redemption amounts for those IDRs) and the deferred compensation amounts.

Although our general partner will not seek reimbursement for the costs of the Class B Membership Interests and deferred compensation plan arrangements, we will record non-cash expense. The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R). As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value. Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates. Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control. Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period. These assumptions were used to estimate the total amount that would be paid under the Class B Membership awards through the final vesting date and are do not represent the contractual amounts payable under these awards at the reporting date. The estimated total amount was discounted to December 31, 2008 using a discount rate of 16%, representing the risks inherent in the assumptions we used and the time until final vesting. Due to the limited number of participants in the Class B Membership awards, we assumed a forfeiture rate of zero. At December 31, 2008, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million. The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards. Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives. The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded $3.4 million. Due to the vesting conditions for the awards, the amounts to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero. Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at December 31, 2008. This expense will be recorded on an accelerated basis to align with the requisite service period of the award. Changes in our assumptions will change the amount of compensation cost we record.

40

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Major Customers and Credit Risk

Due to the nature of our supply and logistics operations, a disproportionate percentage of our trade receivables constitute obligations of oil companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of integrated and large independent energy companies with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements.

We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met.

Shell Oil Company accounted for 14.6% of total revenues in 2008. Shell Oil Company and Occidental Energy Marketing, Inc. accounted for 20.7% and 11.2% of total revenues in 2007, respectively. Occidental Energy Marketing, Inc., Shell Oil Company and Calumet Specialty Products Partners, L.P. accounted for 20.3%, 19.1% and 10.9% of total revenues in 2006, respectively. The revenues from these five customers in all three years relate primarily to our supply and logistics operations.

17. 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. The derivative instruments that we use consist primarily of futures and options contracts traded on the NYMEX which we use to hedge our exposure to commodity prices, primarily crude oil, fuel oil and petroleum products.

Additionally, DG Marine entered into a series of interest rate swap contracts with two financial institutions related to $32.9 million of the outstanding debt under the DG Marine credit facility. These swaps effectively convert this portion of DG Marine’s debt from floating LIBOR rate to a series of fixed rates through July 2011. We have determined that these swaps are effective cash flow hedges of DG Marine’s interest rate exposure.

At December 31, 2008 and 2007, we had no commodity price risk derivatives that were designated as hedges for financial reporting purposes. Therefore, the derivative contracts were marked to fair value based on the closing price for the contracts at the end of each period and an asset or liability was recorded for the fair value and the change in fair value was recorded in our consolidated statements of operations.

The following table summarizes the liabilities on our consolidated balance sheet that are related to the fair value of our open derivative positions:

	December 31,
	2008			2007
Decrease in other current assets	$	(488	)	$	(744	)
Increase in accrued liabilities		(698	)		—
Increase in other long-term liabilities		(1,266	)		—
Total liabilities	$	(2,452	)	$	(744	)

41

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The liabilities related to the fair value of our open positions consists of unrealized gains/losses recognized in earnings and unrealized losses deferred to other comprehensive income (“OCI”) as follows, by category (losses designated in parentheses):

	December 31, 2008												December 31, 2007
	Total Liabilities			Losses			Noncontrolling Interests			OCI			Total Liabilities			Losses
Commodity price risk derivatives	$	(488	)	$	(488	)	$	—		$	—		$	(744	)	$	(744	)
Interest rate risk hedging by DG Marine		(1,964	)		—			(1,002	)		(962	)		—			—
Total	$	(2,452	)	$	(488	)	$	(1,002	)	$	(962	)	$	(744	)	$	(744	)

In each year, the impact on earnings of our unrealized losses from commodity price risk derivatives in the table above is included in the Consolidated Statements of Operations under the caption “Supply and logistics costs.”

The net loss recorded in AOCI and noncontrolling interests is expected to be reclassified to future earnings contemporaneously as interest expense associated with the underlying debt under the DG Marine credit facility is recorded. We expect the total net loss to be reclassified into earnings during the period the swaps are outstanding, with $0.7 million of net loss expected to be reclassified in 2009 and a total of $1.3 million reclassified to earnings during 2011 and 2012. Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified to earnings will differ and could vary materially as a result of changes in market conditions.

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 December 31, 2008 and December 31, 2007.

18. Fair-Value Measurements

As discussed in Note 2, effective January 1, 2008 we partially adopted SFAS 157. As defined in SFAS 157, fair value as the price that would be received from selling an asset, or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Whenever possible, we use market data that market participants would use when pricing an asset or liability. These inputs can be either readily observable or market corroborated. We apply the market approach for recurring fair value measurements related to our derivatives. SFAS 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement)

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

	Fair Value at December 31, 2008
Recurring Fair Value Measures	Level 1			Level 2		Level 3
Commodity derivatives (based on quoted market prices on NYMEX)	$	(488	)	$	—	$	—
Interest rate swaps	$	—		$	—	$	(1,964	)

42

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Level 1

Included in Level 1 of the fair value hierarchy are commodity 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 of the fair value hierarchy.

Level 3

Included within Level 3 of the fair value hierarchy are our interest rate swaps. The fair value of our interest rate swaps is based on indicative broker price quotations. These derivatives are included in Level 3 of the fair value hierarchy because broker price quotations used to measure fair value are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact. However, the fair value of these Level 3 derivatives is not based upon significant management assumptions or subjective inputs.

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as level 3 in the fair value hierarchy:

	Year Ended December 31, 2008
Balance as of January 1, 2008	$	—
Realized and unrealized gains (losses)-
Included in other comprehensive income		(962	)
Included in noncontrolling interests		(1,002	)
Balance as of December 31, 2008	$	(1,964	)

See Note 17 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.

19. Commitments and Contingencies

Commitments and Guarantees

In 2008, we entered into a new office lease for our corporate headquarters that extends until January 31, 2016. We lease office space for field offices under leases that expire between 2008 and 2013. To transport products, we lease tractors and trailers for our crude oil gathering and marketing activities and lease barges and railcars for our refinery services segment. In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS and caustic soda. Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput. We have no minimum volumetric or financial requirements remaining on our pipeline lease.

The future minimum rental payments under all non-cancelable operating leases as of December 31, 2008, were as follows (in thousands).

	Office Space		Transportation Equipment		Terminals and Tanks		Total
2009	$	745	$	3,322	$	1,257	$	5,324
2010		813		3,071		322		4,206
2011		794		2,639		322		3,755
2012		762		1,552		322		2,636
2013		733		726		322		1,781
2014 and thereafter		1,534		2,583		6,950		11,067
Total minimum lease obligations	$	5,381	$	13,893	$	9,495	$	28,769

43

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Total operating lease expense was as follows (in thousands).

Year ended December 31, 2008	$	8,757
Year ended December 31, 2007	$	6,079
Year ended December 31, 2006	$	3,258

We have guaranteed the payments by our operating partnership to the banks under the terms of our credit facility related to borrowings and letters of credit. To the extent liabilities exist under the letters of credit, such liabilities are included in the consolidated balance sheet. Borrowings at December 31, 2008 were $320.0 million and are reflected in the consolidated balance sheet. We have also guaranteed the payments by our operating partnership under the terms of our operating leases of tractors and trailers. Such obligations are included in future minimum rental payments in the table above.

We guarantee $7.5 million of the outstanding debt of DG Marine under its credit facility. This guarantee will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00. The outstanding debt of DG Marine in included in our Consolidated Balance Sheets. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.

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

We guaranty 50% of the obligations of Sandhill under a credit facility with a bank. At December 31, 2008, Sandhill owed $3.0 million; therefore our guarantee was $1.5 million. Sandhill makes principal payments for this obligation totaling $0.6 million per year. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.

In general, we expect to incur expenditures in the future to comply with increasing levels of regulatory safety standards. While the total amount of increased expenditures cannot be accurately estimated at this time, we expect that our annual expenditures for integrity testing, repairs and improvements under regulations requiring assessment of the integrity of crude oil pipelines to average from $1.0 million to $1.5 million.

We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may not substantially affect our business.

Other Matters

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.

20. Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Other than with respect to our corporate subsidiaries and the Texas Margin Tax, 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 transactions 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.”

44

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 is 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.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted FIN 48 effective January 1, 2007. The adoption did not have any impact on our consolidated financial statements.

As of December 31, 2007 we had unrecognized tax benefits of $1.0 million. At December 31, 2008 we have unrecognized tax benefits of $2.6 million. The change in the unrecognized tax benefits are a result of additions related to current year tax positions. If the unrecognized tax benefits at December 31, 2008 were recognized, $2.6 million would affect our effective income tax rate. There are no uncertain tax positions as of December 31, 2008 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly decrease during 2009.

Our income tax provision (benefit) is as follows:

	Year Ended December 31,
	2008			2007
Current:
Federal	$	2,979		$	1,665
State		872			339
Total current income tax expense		3,851			2,004
Deferred:
Federal		(3,850	)		(2,432	)
State		(363	)		(226	)
Total deferred income tax benefit		(4,213	)		(2,658	)
Total income tax benefit	$	(362	)	$	(654	)

45

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 2008 balance sheet date. We believe we will utilize all of our deferred tax assets at December 31, 2008, and therefore have provided no valuation allowance against our deferred tax assets. As of December 31, 2008, we have federal income tax net operating loss carryforwards of $4.1 million which, if not used, will begin to expire in 2027. Deferred tax assets and liabilities consist of the following:

	December 31,
	2008			2007
Deferred tax assets:
Current:
Other current assets	$	271		$	43
Other		97			17
Total current deferred tax asset		368			60
Net operating loss carryforwards - federal		1,415			861
Net operating loss carryforwards - state		128			80
Total long-term deferred tax asset		1,543			941
Total deferred tax assets		1,911			1,001
Deferred tax liabilities:
Current:
Other		(3	)		(24	)
Long-term:
Fixed assets		(9,868	)		(11,125	)
Intangible assets		(6,937	)		(8,962	)
Total long-term liability		(16,805	)		(20,087	)
Total deferred tax liabilities		(16,808	)		(20,111	)
Total net deferred tax liability	$	(14,897	)	$	(19,110	)

Our income tax benefit varies from the amount that would result from applying the federal statutory income tax rate to income before income taxes as follows:

	Year Ended December 31,
	2008			2007
Income (loss) before income taxes	$	25,463		$	(14,205	)
Partnership income (loss) not subject to tax		(30,902	)		8,894
Income (loss) subject to income taxes		(5,439	)		(5,311	)
Tax benefit at federal statutory rate		(1,904	)	$	(1,859	)
State income taxes, net of federal benefit		357			33
Effects of FIN 48, federal and state		1,431			1,168
Return to provision, federal and state		(258	)		—
Other		12			4
Income tax benefit	$	(362	)	$	(654	)
Effective tax rate on income (loss) before income taxes		-1	%		5	%

46

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

21. Quarterly Financial Data (Unaudited)

The table below summarizes our unaudited quarterly financial data for 2008 and 2007.

	2008 Quarters										Total
	First		Second			Third		Fourth			Year
Revenues	$	486,185	$	640,540		$	636,919	$	378,040		$	2,141,684
Operating income	$	1,759	$	11,032		$	13,381	$	11,719		$	37,891
Net income attributable to Genesis Energy, L.P.	$	1,645	$	7,328		$	10,763	$	6,353		$	26,089
Net income per common unit - basic	$	0.03	$	0.17		$	0.25	$	0.14		$	0.59
Net income per common unit - diluted	$	0.03	$	0.17		$	0.25	$	0.14		$	0.59
Cash distributions per common unit(1)	$	0.2850	$	0.3000		$	0.3150	$	0.3225		$	1.2225
	2007 Quarters										Total
	First		Second			Third		Fourth			Year
Revenues	$	183,564	$	201,016		$	354,270	$	460,803		$	1,199,653
Operating income (loss)	$	1,580	$	(1,319	)	$	7,043	$	(12,679	)	$	(5,375	)
Net income (loss) attributable to Genesis Energy, L.P.	$	1,585	$	(1,372	)	$	1,699	$	(15,462	)	$	(13,550	)
Net income (loss) per common unit - basic and diluted	$	0.11	$	(0.09	)	$	0.06	$	(0.50	)	$	(0.66	)
Cash distributions per common unit(1)	$	0.21	$	0.22		$	0.23	$	0.27		$	0.93

(1) Represents cash distributions declared and paid in the applicable period.

47

Schedule I - Condensed Financial Information

Genesis Energy, L.P. (Parent Company Only)

Condensed Statements of Income and Comprehensive Income

	Years Ended December 31,
	2008			2007			2006
				(in thousands)
Equity in earnings (losses) of subsidiaries	$	26,089		$	(13,550	)	$	8,381
Net income (loss)		26,089			(13,550	)		8,381
Other comprehensive loss of subsidiary		(962	)		—			—
Total comprehensive income (loss)	$	25,127		$	(13,550	)	$	8,381

Condensed Balance Sheets

	December 31,
	2008			2007
	(in thousands)
Assets
Cash	$	3		$	10
Investment in subsidiaries		665,334			664,480
Advances to subsidiaries		91			84
Total Assets	$	665,428		$	664,574
Partners’ Capital
Limited Partners	$	649,046		$	647,340
General Partner		17,344			17,234
Accumulated other comprehensive income		(962	)		—
Total Partners’ Capital	$	665,428		$	664,574

See accompanying notes to condensed financial statements.

48

Schedule I - Condensed Financial Information—Continued

Genesis Energy, L.P. (Parent Company Only)

Condensed Statements of Cash Flows

	Years Ended December 31,
	2008			2007			2006
	(in thousands)
Cash Flows from Operating Activities:
Net income (loss)	$	26,089		$	(13,550	)	$	8,381
Equity in (earnings) losses of GCO		(15,773	)		13,550			(8,381	)
Equity in (earnings) losses of GNEJD		(10,316	)		—			—
Change in advances to GCO		(7	)		4			—
Net cash (used in) provided by operating activities		(7	)		4			—
Cash Flows from Investing Activities:
Investment in GCO		(511	)		(216,172	)		—
Distributions from GCO - return of investment		50,534			17,175			10,408
Net cash provided by (used in) investing activities		50,023			(198,997	)		10,408
Cash Flows from Financing Activities:
Issuance of limited and general partner interests, net		511			216,172			—
Distributions to limited and general partners		(50,534	)		(17,175	)		(10,408	)
Net cash (used in) provided by financing activities		(50,023	)		198,997			(10,408	)
Net (decrease) increase in cash		(7	)		4			—
Cash at beginning of period		10			6			6
Cash at end of period	$	3		$	10		$	6

See accompanying notes to condensed financial statements.

49

Schedule I - Condensed Financial Statements—Continued

Genesis Energy, L.P. (Parent Company Only)

Notes to Condensed Financial Statements

1. Basis of Presentation

Genesis Energy, L.P., or GEL, is the owner of 99.99% of Genesis Crude Oil, L.P., or GCO and 100% of Genesis NEJD Holdings, LLC, or GNEJD. These parent company only financial statements for GEL summarize the results of operations and cash flows for the years ended December 31, 2008, 2007 and 2006, and GEL’s financial position at December 31, 2008 and 2007. In these statements, GEL’s investments in GCO and GNEJD are stated on the equity method basis of accounting. The GEL statements should be read in conjunction with the consolidated financial statements of Genesis Energy, L.P.

As discussed in Note 10 of the Notes to the Consolidated Financial Statements, the terms of the credit facility with GCO, limit the amount of distributions that GCO and its subsidiaries may pay to GEL. Such distributions may not exceed the sum of the distributable cash generated by GCO and its subsidiaries for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. This restriction results in the restricted net assets (as defined in Rule 4-08 (e)(3) of Regulation S-X) of GEL’s subsidiary exceeding 25% of the consolidated net assets of GEL and its subsidiaries.

2. Contingencies

GEL guarantees the obligations of GCO under our credit facility. See Note 10 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P. for a description of GCO’s credit facility

GEL guarantees the obligations of GCO under our lease with Paccar Leasing Services. See Note 19 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P.

GEL has guaranteed crude oil and petroleum products purchases of GCO and its subsidiaries. These guarantees, totaling $40.8 million, were provided to counterparties. To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated financial statements of Genesis Energy, L.P.

GEL has guaranteed $7.5 million of the outstanding debt of DG Marine under its credit facility. This guarantee will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00.

3. Supplemental Cash Flow Information

In May 2008, additional limited partner interests in GCO with a value of $25 million were issued to GEL. GEL issued common units with an equal value as part of the consideration in acquisition of the Free State Pipeline from Denbury. In July 2008, additional limited partner interests in GCO with a value of $16.7 million were issued to GEL. GEL issued common units with an equal value as part of the consideration in the Grifco acquisition. These transactions are non-cash transactions and are not included in the Statements of Cash Flows in investing or financing activities.

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