GENESIS ENERGY LP - FORM 8-K - EX-99.4 - EXHIBIT 99.4

Attached files

file	filename
EX-23.2 - EXHIBIT 23.2 - GENESIS ENERGY LP	ex23_2.htm
EX-99.2 - EXHIBIT 99.2 - GENESIS ENERGY LP	ex99_2.htm
EX-99.1 - EXHIBIT 99.1 - GENESIS ENERGY LP	ex99_1.htm
8-K - GENESIS ENERGY LP 8-K 9-26-2011 - GENESIS ENERGY LP	form8k.htm
EX-99.3 - EXHIBIT 99.3 - GENESIS ENERGY LP	ex99_3.htm
EX-23.1 - EXHIBIT 23.1 - GENESIS ENERGY LP	ex23_1.htm

EXHIBIT 99.4

Item 8. Financial Statements and Supplementary Data

The information required hereunder is included in this report as set forth in the “Index to Consolidated Financial Statements” on page 1.

GENESIS ENERGY, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

		Page

Financial Statements of Genesis Energy, L.P.

Report of Independent Registered Public Accounting Firm		F-1

Consolidated Balance Sheets, December 31, 2010 and 2009		F-2

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		F-3

Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2010, 2009 and 2008		F-4

Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2010, 2009 and 2008		F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		F-6

Notes to Consolidated Financial Statements		F-7

Financial Statements of Significant Equity Investee – Cameron Highway Oil Pipeline Company

Independent Auditors’ Report		F-51

Balance Sheet, December 31, 2010		F-52

Statement of Operations for the Period from November 23, 2010 to December 31, 2010		F-53

Statement of Cash Flows for the Period from November 23, 2010 to December 31, 2010		F-54

Statement of Partners’ Capital for the Period from November 23, 2010 to December 31, 2010		F-55

Notes to Financial Statements		F-56

All 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.

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, 2010 and 2009, and the related consolidated statements of operations, comprehensive (loss) income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

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, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2011 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

As discussed in Note 12 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for a change in operating segments. As discussed in Note 22 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the addition of a footnote containing condensed consolidating financial information relating to subsidiary guarantees of registered debt.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 16, 2011

(September 26, 2011 as to Notes 12 and 22)

F-1

GENESIS ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,			December 31,
	2010			2009

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,762		$	4,148
Accounts receivable - trade, net		171,550			129,865
Inventories		55,428			40,204
Other		19,798			15,027
Total current assets		252,538			189,244

FIXED ASSETS, at cost		373,339			373,927
Less: Accumulated depreciation		(108,283	)		(89,040	)
Net fixed assets		265,056			284,887

NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income		168,438			173,027
EQUITY INVESTEES AND OTHER INVESTMENTS		343,434			15,128
INTANGIBLE ASSETS, net of amortization		120,175			136,330
GOODWILL		325,046			325,046
OTHER ASSETS, net of amortization		32,048			24,465

TOTAL ASSETS	$	1,506,735		$	1,148,127

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	165,978		$	117,625
Accrued liabilities		40,736			23,803
Total current liabilities		206,714			141,428

SENIOR SECURED CREDIT FACILITIES		360,000			366,900
SENIOR UNSECURED NOTES		250,000			-
DEFERRED TAX LIABILITIES		15,193			15,167
OTHER LONG-TERM LIABILITIES		5,564			5,699
COMMITMENTS AND CONTINGENCIES (Note 19)

PARTNERS' CAPITAL:
Class A common unitholders, 64,575 and 39,488 units issued and outstanding at December 31, 2010 and 2009, respectively		669,261			585,554
Class B common unitholders, 40 units issued and outstanding at December 31, 2010		3			-
General partner		-			11,152
Accumulated other comprehensive loss		-			(829	)
Total Genesis Energy, L.P. partners' capital		669,264			595,877
Noncontrolling interests		-			23,056
Total partners' capital		669,264			618,933

TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,506,735		$	1,148,127

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

F-2

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Year Ended December 31,
	2010			2009			2008
REVENUES:
Supply and logistics	$	1,894,612		$	1,243,044		$	1,870,063
Refinery services		151,060			141,365			225,374
Pipeline transportation services		55,652			50,951			46,247
Total revenues		2,101,324			1,435,360			2,141,684

COSTS AND EXPENSES:
Supply and logistics costs:
Product costs		1,761,161			1,115,809			1,736,637
Operating costs		97,701			88,087			84,937
Refinery services operating costs		88,094			88,910			166,096
Pipeline transportation operating costs		14,777			13,024			15,224
General and administrative		113,406			40,413			29,500
Depreciation and amortization		53,557			62,581			71,370
Net loss on disposal of surplus assets		12			160			29
Impairment expense		-			5,005			-
Total costs and expenses		2,128,708			1,413,989			2,103,793

OPERATING (LOSS) INCOME		(27,384	)		21,371			37,891
Equity in earnings of joint ventures		2,355			1,547			509
Interest expense		(22,924	)		(13,660	)		(12,937	)
(Loss) income before income taxes		(47,953	)		9,258			25,463
Income tax (expense) benefit		(2,588	)		(3,080	)		362

NET (LOSS) INCOME		(50,541	)		6,178			25,825

Net loss attributable to noncontrolling interests		2,082			1,885			264
NET (LOSS) INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P.	$	(48,459	)	$	8,063		$	26,089




NET INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P. PER COMMON UNIT:
Basic and Diluted	$	0.49		$	0.51		$	0.59

WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted		40,560			39,471			38,961

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

F-3

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In thousands)

	Year Ended December 31,
	2010			2009			2008

Net (loss) income	$	(50,541	)	$	6,178		$	25,825
Change in fair value of derivatives:
Current period reclassification to earnings		2,112			784			33
Changes in derivative financial instruments - interest rate swaps		(424	)		(508	)		(1,997	)
Comprehensive (loss) income		(48,853	)		6,454			23,861
Comprehensive loss attributable to noncontrolling interests		1,223			1,742			1,266
Comprehensive (loss) income attributable to Genesis Energy, L.P.	$	(47,630	)	$	8,196		$	25,127

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

F-4

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(In thousands)

	Partners' Capital
	Number of Class A Common			Class A Common			Class B Common		General			Accumulated Other Comprehensive			Non-controlling
	Units			Unitholders			Unitholders		Partner			Loss			Interests			Total

Partners' capital, January 1, 2008		38,253		$	615,265		$	-	$	16,539		$	-		$	570		$	632,374
Comprehensive income:
Net income (loss)		-			23,485			-		2,604			-			(264	)		25,825
Interest rate swap losses reclassified to interest expense		-			-			-		-			16			17			33
Interest rate swap loss		-			-			-		-			(978	)		(1,019	)		(1,997	)
Cash contributions		-			-			-		511			-			25,505			26,016
Cash distributions		-			(47,529	)		-		(3,005	)		-			(5	)		(50,539	)
Issuance of units for cash		2,037			41,667			-		-			-			-			41,667
Issuance of units under LTIP		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
Comprehensive income:
Net income (loss)		-			21,469			-		(13,406	)		-			(1,885	)		6,178
Interest rate swap losses reclassified to interest expense		-			-			-		-			383			401			784
Interest rate swap loss		-			-			-		-			(250	)		(258	)		(508	)
Cash contributions		-			-			-		9			-			-			9
Contribution for management
compensation (Note 11)		-			-			-		14,104			-			-			14,104
Cash distributions		-			(53,876	)		-		(6,204	)		-			(6	)		(60,086	)
Issuance of units under LTIP		31			990			-		-			-			-			990
Partners' capital, December 31, 2009		39,488			585,554			-		11,152			(829	)		23,056			618,933
Comprehensive loss:
Net income (loss)		-			17,933			-		(66,392	)		-			(2,082	)		(50,541	)
Interest rate swap losses reclassified to interest expense		-			-			-		-			1,035			1,077			2,112
Interest rate swap loss		-			-			-		-			(206	)		(218	)		(424	)
Issuance of units for cash		5,175			116,347			-		-			-			-			116,347
Cash contributions		-			-			-		2,528			-			13			2,541
Contribution for management compensation (Note 11)		-			-			-		76,923			-			-			76,923
Cash distributions		-			(58,983	)		-		(11,369	)		-			(7	)		(70,359	)
Acquisition of noncontrolling interest in DG Marine (Note 3)		-			(4,920	)		-		(100	)		-			(21,268	)		(26,288	)
Issuance of units in exchange for general partner interest (Note 11)		19,814			13,310			3		(12,742	)		-			(571	)		-
Issuance of units under LTIP		98			20			-		-			-			-			20
Partners' capital, December 31, 2010		64,575		$	669,261		$	3	$	-		$	-		$	-		$	669,264

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

F-5

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(50,541	)	$	6,178		$	25,825
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, amortization and impairment		53,557			67,586			71,370
Amortization and write-off of credit facility issuance costs		3,082			2,503			1,437
Amortization of unearned income and initial direct costs on direct financing leases		(17,651	)		(18,095	)		(10,892	)
Payments received under direct financing leases		21,854			21,853			11,519
Equity in earnings of investments in joint ventures		(2,355	)		(1,547	)		(509	)
Distributions from joint ventures - return on investment		3,623			950			1,272
Non-cash effect of equity-based compensation plans		4,706			4,248			(2,063	)
Non-cash compensation charge		76,923			14,104			-
Deferred and other tax liabilities		1,337			1,914			(2,771	)
Other, net		1,415			(46	)		882
Net changes in components of operating assets and liabilities (See Note 14)		(5,487	)		(9,569	)		(1,262	)
Net cash provided by operating activities		90,463			90,079			94,808

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		(12,400	)		(30,332	)		(37,354	)
CO2 pipeline transactions and related costs		-			-			(228,891	)
Distributions from joint ventures - return of investment		2,859			-			886
Investments in joint ventures and other investments		(332,462	)		(83	)		(2,397	)
Acquisition of Grifco assets		-			-			(66,686	)
Other, net		1,265			1,182			718
Net cash used in investing activities		(340,738	)		(29,233	)		(333,724	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		691,829			255,300			531,712
Bank repayments		(698,729	)		(263,700	)		(236,412	)
Proceeds from issuance of senior unsecured notes		250,000			-			-
Credit facility and senior unsecured notes issuance fees		(14,586	)		(422	)		(2,255	)
Issuance of common units for cash		116,347			-			-
Redemption of common units for cash		-			-			(16,667	)
General partner contributions		2,528			9			511
Noncontrolling interests contributions, net of distributions		6			(6	)		25,500
Acquisition of noncontrolling interest in DG Marine		(26,288	)		-			-
Distributions to common unitholders		(58,983	)		(53,876	)		(47,529	)
Distributions to general partner interest		(11,369	)		(6,204	)		(3,005	)
Other, net		1,134			(6,784	)		(5,805	)
Net cash provided by (used in) financing activities		251,889			(75,683	)		246,050

Net increase (decrease) in cash and cash equivalents		1,614			(14,837	)		7,134
Cash and cash equivalents at beginning of period		4,148			18,985			11,851

Cash and cash equivalents at end of period	$	5,762		$	4,148		$	18,985

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

F-6

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 three divisions:

Pipeline transportation of crude oil and carbon dioxide (or “CO2”);

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

Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil, petroleum products and CO2.

In February 2010, new investors, together with members of our executive management team, acquired our general partner. At that time, our general partner owned all our 2% general partner interest and all of our incentive distribution rights, or IDRs. At that time, in respect of its general partner interest and IDRs, our general partner was entitled to over 50% of any increased distributions we would pay in respect of our outstanding equity.

On December 28, 2010, we permanently eliminated our IDRs and converted our 2% general partner interest into a non-economic interest, which we refer to as our IDR Restructuring. We issued Class A Units, Class B Units and Waiver Units to the former stakeholders of our general partner in exchange for the elimination of our IDRs. See Note 11 for additional discussion of our capital structure.

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, 2010 and 2009 and our results of operations, cash flows and changes in partners’ capital for the years ended December 31, 2010, 2009 and 2008. All intercompany balances and 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, and Genesis Energy, LLC.

The inclusion of Genesis Energy, LLC in our Consolidated Financial Statements was effective December 28, 2010 due to our IDR Restructuring. See Notes 1 and 11.

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: Cameron Highway Oil Pipeline Company (“Cameron Highway”), T&P Syngas Supply Company (“T&P Syngas”) and Sandhill Group, LLC (“Sandhill”). We account for our 50% investments in Cameron Highway, T&P Syngas and Sandhill by the equity method of accounting. See Notes 3 and 8.

Cameron Highway Oil Pipeline Company

On November 23, 2010, we acquired a 50% equity interest in Cameron Highway Oil Pipeline Company, a joint venture that owns and operates a crude oil pipeline system in the Gulf of Mexico. Enterprise Products Partners, L.P. indirectly owns the remaining 50% interest in, and operates, the joint venture.

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.

F-7

Sandhill Group, LLC

We own a 50% interest in Sandhill. Reliant Processing Ltd. holds the other 50% interest in Sandhill and manages the daily operations of the joint venture. 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

Until December 28, 2010, our general partner, which owns a 0.01% general partner interest in Genesis Crude Oil, L.P., was not one of our subsidiaries See Note 1.

Until July 29, 2010, TD Marine, LLC, a related party, owned the remaining 51% economic interest in DG Marine. See Note 3.

As a result of our IDR Restructuring and the acquisition of the 51% of DG Marine from TD Marine, we reclassified the acquired noncontrolling interest in Genesis Crude Oil, L.P. and DG Marine to Genesis Energy, L.P. partners’ capital. The net interest of those parties in our results of operations and financial position are reflected in our Consolidated Financial Statements as noncontrolling interests for the periods prior to the dates of the respective transactions.

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) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) 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.

We utilize our credit review process 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. Such financial performance assurances most commonly provided to us include standby letters of credit, “parental” guarantees and advance cash payments.

We review our outstanding accounts receivable balances on a regular basis and record an allowance 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.

F-8

Inventories

Crude oil and petroleum products inventories held for sale are valued at the lower of 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 barges and push boats, 10 to 20 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 10 years for buildings and improvements, 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 6.

Direct Financing Leasing Arrangements

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.

We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit rating and financial position of the lessee. See Note 7.

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. These assets are included in Other Assets in our Consolidated Balance Sheets. See Note 9.

Intangible and Other Assets

Intangible assets with finite useful lives are 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 amortizing 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.

F-9

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. No impairment has occurred of intangible assets in any of the periods presented.

Costs incurred in connection with the issuance of long-term debt and certain amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully-amortized debt issuance costs and the related accumulated amortization are written-off in conjunction with the refinancing or termination of the applicable debt arrangement.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. 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 may be necessary 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. No goodwill impairment has occurred in any of the periods presented. 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.

Equity-Based Compensation

The compensation cost associated with our stock appreciation rights plan and phantom units issued under our 2010 Long-Term Incentive Plan, which will result in the payment of cash to our employee or directors or our general partner upon exercise, is re-measured each reporting period. The liability and related compensation cost is calculated using a fair value method that takes into consideration the expected future value of the rights at their expected exercise dates and management’s assumptions about expectation of forfeitures prior to vesting.

See Note 15 for information on these plans.

Revenue Recognition

Product Sales - Revenues from the sale of crude oil, petroleum products and CO2 by our supply and logistics segment, natural gas by our pipeline transportation segment, and caustic soda and NaHS by our refinery services segment are recognized when title to the inventory is transferred to the customer, collectability 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.

F-10

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 a reduction of revenue, 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 Consolidated 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.

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 under Supply and logistics revenues.

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..

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 Statements of Operations.

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 Statements of Operations, is included 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. Until July 29, 2010, DG Marine used interest rate swap contracts to manage its exposure to interest rate risk.

Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets 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.

F-11

Fair Value of Current Assets and Current Liabilities

The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature.

Net Income Per Common Unit

Income was first allocated to our general partner based on the amount of incentive distributions to our general partner. We then allocated to our general partner loss in the amount of equity-based compensation costs which our general partner agreed to pay. The remainder was then allocated 98% to the limited partners and 2% to the general partner. Basic net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period. Diluted net income per common unit is calculated in the same manner, but also considers the impact to common units for the potential dilution from phantom units outstanding under our 2007 Long-term Incentive Plan (2007 LTIP). (See Note 15 for discussion of our equity-based compensation.)

In a period of net operating losses, incremental phantom units are excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. During 2009 and 2008, we reported net income; therefore incremental phantom units have been included in the calculation of diluted earnings per unit.

Recent and Proposed Accounting Pronouncements

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test. More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for public entities, for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. Early application is not permitted. We will adopt the new guidance in the first quarter of 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, we do not expect the adoption of this guidance to have an impact on our financial position, results of operations or cash flows.

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption. Early adoption is permitted. We will adopt the new disclosures in the first quarter of 2011. We do not believe that the adoption of this guidance will have a material impact to our financial position, results of operations or cash flows.

In July 2010, the FASB issued guidance which requires companies that hold financing receivables, which include loans, lease receivables, and the other long-term receivables to provide more information in their disclosures about the credit quality of their financing receivables and the credit reserves held against them. On December 31, 2010, we adopted all amendments that require disclosures as of the end of a reporting period, and on January 1, 2011, we adopted all amendments that require disclosures about activity that occurs during a reporting period (the remainder of the accounting guidance). The adoption of this accounting guidance did not have a material impact on our consolidated financial statements.

In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. A fair value measurement is designated as Level 1, 2 or 3 within the hierarchy based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, Level 2 measurements generally reflect the use of significant observable inputs and Level 3 measurements typically utilize significant unobservable inputs. This new guidance requires additional disclosures regarding transfers into and out of Level 1 and Level 2 measurements and requires a gross presentation of activities within the Level 3 roll forward. This guidance was effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance relating to Level 1 and Level 2 transfers as of January 1, 2010, and we adopted the guidance relating to Level 3 measurements on January 1, 2011. Our adoption had no material impact on Consolidated Financial Statements.

F-12

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for Variable Interest Entities, or VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. In contrast, the new guidance requires an enterprise with a variable interest in a VIE to qualitatively assess whether it has a controlling interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation, rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance was effective for us beginning January 1, 2010, and there was no material impact on our Consolidated Financial Statements.

3. Acquisitions

2010 Cameron Highway Oil Pipeline Company Investment

On November 23, 2010, we acquired a 50% equity interest in Cameron Highway Oil Pipeline Company, a joint venture that owns and operates a crude oil pipeline system in the Gulf of Mexico. The purchase price was approximately $330 million plus approximately $2.5 million of purchase price adjustments.

The funding for this acquisition consisted of $330 million in cash from the issuance of 5,175,000 common units at $23.58 per common unit and the issuance of $250 million of senior unsecured notes. Total net proceeds from the common units offering, after deducting underwriting discounts and commissions and estimated offering expenses and including our general partner’s proportionate capital contribution to maintain its 2% general partner interest, were approximately $119 million.

The Cameron Highway pipeline system is a 380-mile 24- and 30-inch diameter pipeline constructed in 2004, with capacity to deliver up to 500,000 barrels per day of crude oil from developments in the Gulf of Mexico to major refining markets along the Texas Gulf Coast located in Port Arthur and Texas City. Enterprise Products Partners, L.P. indirectly owns the remaining 50% interest in, and operates, the joint venture.

The following table presents selected unaudited pro forma financial information incorporating the historical 50% equity interest in Cameron Highway. The effective closing date of our purchase of a 50% equity interest in Cameron Highway was November 23, 2010. As a result, our Consolidated Statements of Operations for the year ended December 31, 2010 includes our 50% equity investment in Cameron Highway for the last five weeks of 2010. 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.

F-13

	Year Ended December 31,
	2010			2009
Pro forma earnings data:
Revenue	$	2,101,324		$	1,435,360
Costs and expenses	$	2,130,430		$	1,415,909
Operating (loss) income		(29,106	)		19,451
Net loss attributable to
Genesis Energy, L.P.	$	(55,001	)	$	(538	)

Basic and diluted earnings per unit:
As reported units outstanding		40,560			39,471
Pro forma units outstanding		44,969			44,646
As reported net income per unit	$	0.49		$	0.51
Pro forma net income per unit	$	0.30		$	0.26

DG Marine Transportation

2008 Initial Investment in DG Marine

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. Until July 29, 2010, TD Marine owned (indirectly) a 51% economic interest in the joint venture, DG Marine, and we owned (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). Grifco financed $12 million of additional purchase consideration that we agreed to pay after we placed the eight new barges in service. At December 31, 2009, all of the seller-financed additional purchase price consideration was paid.

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 was non-recourse to us and TD Marine (other than with respect to our investments in DG Marine). Although DG Marine’s debt was non-recourse to us, our ownership interest in DG Marine was 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.

Until July 29, 2010, DG Marine was a VIE as certain of our voting rights were not proportional to our 49% economic interest. Accounting provisions require the primary beneficiary to consolidate variable interest entities. In determining the primary beneficiary of a 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 were 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 provided to DG Marine. TD Marine had no requirements to make any additional contributions to DG Marine.

As we were considered the primary beneficiary, DG Marine was consolidated in our Consolidated Financial Statements and the 51% ownership interest of TD Marine in the net assets and net income of DG Marine was included in noncontrolling interests in our Consolidated Financial Statements.

The acquisition cost allocated to the assets consisted 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 was owed to Grifco when the barges under construction were placed in service and $2.4 million of transaction costs. The acquisition cost was allocated to the assets acquired based on estimated fair values. Such fair values were developed by management.

F-14

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 is 6 years.

See additional information on intangible assets in Note 9.

2010 Acquisition of Noncontrolling Interest

On July 29, 2010, we acquired TD Marine’s effective 51% interest in DG Marine for $25.5 million in cash, resulting in DG Marine becoming wholly-owned by us. We funded the acquisition with proceeds from our credit agreement, including (i) paying off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million, and (ii) settling DG Marine’s interest rate swaps, which resulted in $1.3 million being reclassified from Accumulated Other Comprehensive Loss (“AOCL”) to interest expense in the third quarter of 2010.

As a result of this transaction, we reclassified the acquired noncontrolling interest in DG Marine of $21.3 million to Genesis Energy, L.P. partners’ capital. Additionally, we reduced our partners’ capital by $26.3 million for the costs related to the transaction ($25.5 million paid to TD Marine and $0.8 million in direct transaction costs associated with the acquisition). The net effect of Genesis Energy, L.P. partners’ capital in our Consolidated Balance Sheet for December 31, 2010 was a decrease of $5.0 million.

2008 Denbury Drop-Down Transactions

On May 30, 2008, we completed two transactions with Denbury Onshore LLC,, a wholly-owned subsidiary of Denbury Resources Inc., (Denbury).

NEJD Pipeline System

In 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million related to the 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 tertiary recovery 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.

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 7.

Free State Pipeline System

We purchased the Free State Pipeline for $75 million from Denbury, 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.

F-15

The Free State Pipeline is an 86-mile, 20” pipeline that extends from CO2 source fields at Jackson Dome, near Jackson, Mississippi, to 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 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 currently 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 of Denbury.

4. Receivables

Accounts receivable – trade, net consisted of the following:

	December 31,
	2010			2009
Accounts receivable - trade	$	172,857		$	131,237
Allowance for doubtful accounts		(1,307	)		(1,372	)
Accounts receivable - trade, net	$	171,550		$	129,865

The following table presents the activity of our allowance for doubtful accounts for the periods indicated:

	December 31,
	2010			2009			2008
Balance at beginning of period	$	1,372		$	1,132		$	-
Charged to costs and expenses		491			558			1,152
Amounts written off		(556	)		(320	)		(20	)
Recoveries		-			2			-
Balance at end of period	$	1,307		$	1,372		$	1,132

5. Inventories

The major components of inventories were as follows:

	December 31,
	2010		2009
Crude oil	$	6,128	$	13,901
Petroleum products		38,588		22,150
Caustic soda		6,309		1,985
NaHS		4,387		2,154
Other		16		14
Total inventories	$	55,428	$	40,204

At December 31, 2010 and 2009, market values of our inventory exceeded recorded costs.

F-16

6. Fixed Assets and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following.

	December 31,
	2010			2009
Land, buildings and improvements	$	14,335		$	14,028
Pipelines and related assets		156,805			156,274
Machinery and equipment		29,433			27,016
Transportation equipment		29,249			31,669
Barges and push boats		122,992			122,913
Office equipment, furniture and fixtures		3,742			4,412
Construction in progress		4,493			4,813
Other		12,290			12,802
Subtotal		373,339			373,927
Accumulated depreciation		(108,283	)		(89,040	)
Total	$	265,056		$	284,887

Depreciation expense was $22.5 million, $25.2 million and $20.4 million for the years ended December 31, 2010, 2009, and 2008, respectively.

Asset Retirement Obligations

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

Asset retirement obligations as of December 31, 2008	$	1,430
Liabilities incurred and assumed in the current period		726
Liabilities settled in the current period		(117	)
Accretion expense		152
Revisions in estimated cash flows		2,647
Asset retirement obligations as of December 31, 2009		4,838
Accretion expense		341
Asset retirement obligations as of December 31, 2010	$	5,179

Liabilities incurred and assumed during the period are for properties acquired during the year. Certain of our unconsolidated affiliates have asset retirement obligations recorded at December 31, 2010 and 2009 relating to contractual agreements. These amounts are immaterial to our Consolidated Financial Statements.

7. Net Investment in 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 related to that lease that began in August 2008.

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

	December 31,
	2010			2009
Total minimum lease payments to be received	$	365,169		$	385,565
Estimated residual values of leased property (unguaranteed)		1,287			1,287
Unamortized initial direct costs		2,184			2,380
Less unearned income		(195,586	)		(212,003	)
Net investment in direct financing leases		173,054			177,229
Less current portion (included in other current assets)		(4,616	)		(4,202	)
Long-term portion of net investment in direct financing leases	$	168,438		$	173,027

F-17

At December 31, 2010, minimum lease payments to be received for each of the five succeeding fiscal years are $21.9 million for 2011, $21.8 million for 2012, $21.3 million per year for 2013 through 2014 and $20.9 million for 2015.

We reviewed the credit risk related to our lease receivables from Denbury at December 31, 2010. Under the terms of the lease arrangement with Denbury related to the NEJD Pipeline, should Denbury’s credit rating decline below certain minimum levels, Denbury is required to provide us with a letter of credit covering the payments owed for a specific period of time. Should Denbury be unable to meet this requirement, the lease arrangement provides that we will be provided other security interest in the pipeline. As a result of a review of Denbury’s current credit rating and the terms of the arrangement, we believe an allowance for credit losses relative to our direct financing leases was not required at December 31, 2010.

8. Equity Investees and Other Investments

Equity Investees

We are accounting for our 50% ownership in each of three joint ventures, Cameron Highway, T&P Syngas and Sandhill under the equity method of accounting. We paid $106.8 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. The table below reflects information included in our Consolidated Financial Statements related to our equity investees.

	Year Ended December 31,
	2010			2009		2008
Genesis' share of operating earnings		3,224			1,262		1,137
Amortization of excess purchase price		(869	)		285		(628	)
Net equity in earnings	$	2,355		$	1,547	$	509

Distributions received	$	6,482		$	950	$	2,158

The combined balance sheet information for the last two years and results of operations data for the last three years for our equity investees was as follows;

	December 31,
BALANCE SHEET DATA:	2010		2009
Current Assets	$	16,402	$	4,906
Fixed assets, net		459,490		4,717
Other Assets		15,424		17,361
Total Assets	$	491,316	$	26,984

Current Liabilities	$	5,509	$	1,406
Other Liabilities		3,876		2,868
Equity		481,931		22,710
Total liabilities and combined equity	$	491,316	$	26,984

F-18

	Year Ended December 31,
	2010		2009		2008
INCOME STATEMENT DATA:
Revenues	$	20,013	$	14,793	$	15,493
Operating Income		5,881		775		3,205
Net Income		5,843		749		3,172

Cameron Highway is only included in the income statement data above for the period in 2010 during which we owned our interest. Audited financial statements for Cameron Highway as of December 31, 2010 and for the period from November 23, 2010 to December 31, 2010 are included in this filing on Form 10-K.

Other Projects

In 2006, we invested in the Faustina Project, a petroleum coke to ammonia project that is in the development stage. As a result of a review of the financing alternatives for the project, requirements for continued funding for the project and the change in control of our general partner in February 2010, we decided not to fund our share of further development in the project. We further determined that the likelihood of a recovery of our investment was remote, and the fair value of the investment was zero. In 2009, we recorded a $5.0 million impairment charge related to our investment in the Faustina Project, reducing the value of that investment in our Consolidated Balance Sheets at December 31, 2009 to zero.

9. Intangible Assets, Goodwill and Other Assets

Intangible Assets

The following table reflects the components of intangible assets being amortized at December 31, 2010:

		December 31, 2010						December 31, 2009
	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	$	53,139	$	41,515	$	94,654	$	41,450	$	53,204
Supply and logistics customer relationships	5		35,430		19,981		15,449		35,430		15,493		19,937
Refinery services supplier relationships	2		36,469		31,476		4,993		36,469		28,551		7,918
Refinery services licensing agreements	6		38,678		15,786		22,892		38,678		11,681		26,997
Supply and logistics trade names - Davison and Grifco	7		18,888		7,530		11,358		18,888		5,444		13,444
Supply and logistics lease	15		13,260		1,618		11,642		13,260		1,144		12,116
Other	5		13,776		1,450		12,326		3,823		1,109		2,714
Total	5	$	251,155	$	130,980	$	120,175	$	241,202	$	104,872	$	136,330

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 supply and logistics lease relates to 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 supply and logistics lease and other intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $26.8 million, $33.1 million and $46.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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

F-19

	2011		2012		2013		2014		2015
Refinery services customer relationships	$	8,972	$	7,056	$	7,116	$	5,597	$	4,405
Supply and logistics customer relationships		3,603		2,819		2,165		1,660		1,275
Refinery services supplier relationships		2,629		2,364		-		-		-
Refinery services licensing agreements		3,690		3,416		3,163		2,928		2,711
Supply and logistics trade name		1,851		1,432		1,237		1,073		932
Supply and logistics lease		474		474		474		474		474
Other		1,747		1,747		1,156		1,103		1,104
Total	$	22,966	$	19,308	$	15,311	$	12,835	$	10,901

Goodwill

The carrying amount of goodwill by business segment at December 31, 2010 and 2009 was $301.9 million in refinery services and $23.1 million in supply and logistics. 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,
	2010			2009
CO2 volumetric production payments	$	43,570		$	43,570
Debt issuance costs - Genesis		15,714			5,022
Credit facility fees - DG Marine		-			2,373
Initial direct costs related to Free State Pipeline lease		1,132			1,132
Deferred tax asset		446			-
Other deferred costs and deposits		78			131
		60,940			52,228
Less - Accumulated amortization		(28,892	)		(27,763	)
Net other assets	$	32,048		$	24,465

Our CO2 volumetric production payments entitle us to a maximum daily quantity of CO2 of 91,875 million cubic feet, or Mcf per day for the calendar years 2011 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, Denbury processes and delivers this CO2 to our industrial customers and receives a fee of $0.16 per Mcf, subject to inflationary adjustments from us. During 2010 this fee averaged $0.2094 per Mcf.

The terms of our CO2 contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. At December 31, 2010, we had seven industrial contracts that expire at various dates between 2011 and 2016, with one small contract extending until 2023.

The CO2 assets are being amortized on a units-of-production method. For 2010, 2009 and 2008, we recorded amortization of $4,254,000, $4,274,000 and $4,537,000, respectively. We have 100.2 Bcf of CO2 remaining under the volumetric production payments at December 31, 2010. 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 $4,020,000 for 2011, $4,007,000 for 2012 and $3,271,000 for 2013 through 2015.

Amortization expense of credit facility fees for the years ended December 31, 2010, 2009 and 2008 was $1.8 million, $1.9 million and $1.4 million, respectively. In the second quarter of 2010, we charged to expense $0.4 million of unamortized fees related to the Genesis credit facility that we restructured in June 2010. Additional fees of $7.6 million related to the restructured facility were deferred in June 2010 and will be amortized over the remaining term of the facility.

We incurred $7.0 million of fees in connection with the issuance of $250 million of senior unsecured notes in November 2010. See Note 10. Amortization of note payable issuance fees for the year ended December 31, 2010 was $0.1 million.

F-20

In connection with our purchase of TD Marine's interest in DG Marine on July 29, 2010, the outstanding balance on the DG Marine credit facility was repaid. As a result, we charged to expense $0.8 million of unamortized fees related to the DG Marine facility in the third quarter of 2010.

Total amortization of credit facility fees and notes payable issuance fees and other deferred costs for the next five years will be $1.8 million per year for 2011 through 2014 and $0.9 million for 2015.

10. Debt

At December 31, 2010 our obligations under debt arrangements consisted of the following:

	December 31,
	2010		2009

Genesis Senior Secured Credit Facility	$	360,000	$	320,000
Senior Unsecured Notes		250,000		-
DG Marine Credit Facility (non-recourse to Genesis)		-		46,900
Total Long-Term Debt	$	610,000	$	366,900

We believe the amount included in our Consolidated Balance Sheet for the debt outstanding under our revolving credit agreement approximates fair value due to the recent restructuring of our credit agreement. At December 31, 2010, the fair value of our senior unsecured notes was approximately $250.3 million.

Genesis Credit Facility

On June 29, 2010, we restructured our senior secured credit facility with a syndicate of banks led by BNP Paribas. We have a $525 million senior secured credit facility, which includes the ability to increase the size of the facility up to $650 million, with approval of lenders. The credit facility includes a $75 million hedged crude oil and petroleum products inventory loan sublimit based on 90% of the hedged value of the inventory. Our inventory borrowing base is recalculated monthly. Additionally up to $100 million of the credit facility can be used for letters of credit.

At December 31, 2010, we had $360 million borrowed under our credit agreement, with $43.9 million of that amount designated as a loan under the inventory sublimit. Additionally, we had $4.6 million in letters of credit outstanding at December 31, 2010. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 30, 2015. The total amount available for borrowings at December 31, 2010 was $160.4 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 an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus ½ of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.5% to 2.5% for alternate base rate borrowings and from 2.5% to 3.5% for Eurodollar rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At December 31, 2010, the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Eurodollar rate borrowings.

Letter of credit fees will range from 2.50% to 3.50% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2010, our letter of credit rate was 2.75%.

We pay a commitment fee on the unused portion of the $525 million maximum facility amount. The commitment fee is 0.50%.

Our credit facility is secured by liens on a substantial portion of our assets, and by guarantees by all of our restricted subsidiaries (as defined in the credit facility).

F-21

Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics - a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to EBITDA (as defined and adjusted) and cannot exceed 5.00 to 1.00 (5.50 to 1.00 in an acquisition period). Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot exceed 3.75 to 1.00 (4.25 to 1.00 in an acquisition period). Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense and must be greater than 2.75 to 1.00 (3.00 to 1.00 during an acquisition period.

Senior Unsecured Notes

On November 18, 2010, we completed the issuance of $250 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2018. The notes were sold at face value. Interest payments are due on June 15 and December 15 of each year, beginning June 15, 2011. We used the net proceeds from this offering to finance in part the purchase price and related transaction costs for the acquisition of a 50% equity interest in Cameron Highway.

The notes were co-issued by Genesis Energy Finance Corporation (which has no independent asset or operations) and are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly-owned subsidiaries. In connection with the issuance of the notes, we agreed to register the notes with the Securities and Exchange Commission no later than November 18, 2011.

We have the right to redeem the notes at any time after December 15, 2013 at a premium to the face amount of the notes that varies based on the time remaining to maturity of the notes. Prior to December 15, 2013, we may also redeem up to 35% of the principal amount for 107.875% of the face amount with the proceeds from an equity offering of our common units.

Covenants and Compliance

Our credit agreement and the indenture governing the senior notes contain cross-default provisions. Our credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, those agreements contain various covenants limiting our ability to, among other things:

incur indebtedness if certain financial ratios are not maintained;

grant liens;

engage in sale-leaseback transactions; and

sell substantially all of our assets or enter into a merger or consolidation.

A default under our credit documents would permit the lenders there under to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not restricted. As of December 31, 2010, we were in compliance with the financial covenants contained in our credit facility and indenture.

DG Marine Credit Facility

In connection with our purchase of the 51% interest in DG Marine we did not already own on July 29, 2010, the outstanding balance on the DG Marine credit facility was repaid. See Note 3.

11. Partners’ Capital and Distributions

Until December 28, 2010, our partners’ capital consisted of common units (Class A Units), representing a 98% aggregate ownership interest in the Partnership and its subsidiaries (after giving effect to the general partner interest), and a 2% general partner interest. Our general partner owned all of our general partner interest, all of our incentive distribution rights (IDRs), and all of the 0.01% general partner interest in Genesis Crude Oil, L.P. (which was reflected as a noncontrolling interest in the Consolidated Balance Sheet at December 31, 2009.)

On December 28, 2010, the incentive distribution rights held by our general partner were eliminated and the 2% general partner interest in us that our general partner held was converted into a non-economic general partner interest. We refer to this transaction as the IDR Restructuring. The former owners of our general partner received approximately 27,000,000 units in us, consisting of: (i) approximately 19,960,000 traditional common units that were re-named “Common Units – Class A,” or Class A Units, (ii) approximately 40,000 common units designated “Common Units – Class B,” or Class B Units, with rights, preferences and privileges of the Class A Units and rights to elect our board of directors and convertible into Class A Units and (iii) approximately 7,000,000 units designated “Waiver Units,” or Waiver Units, convertible into Class A Units.

F-22

The Class A Units are traditional common units in us. The Class B Units are identical to the Class A Units and, accordingly, have voting and distribution rights equivalent to those of the Class A Units, and, in addition, Class B Units have the right to elect all of our board of directors and are convertible into Class A Units under certain circumstances. The Waiver Units are non-voting securities entitled to a minimal preferential quarterly distribution and are comprised of four classes (designated Class 1, Class 2, Class 3 and Class 4) of 1,750,000 authorized units each. The Waiver Units have the right to convert into Genesis common units in four equal installments in the calendar quarter during which each of our common units receives a quarterly distribution of at least $0.43, $0.46, $0.49 and $0.52, if our distribution coverage ratio (after giving effect to the then convertible Waiver Units) would be at least 1.1 times..

At December 31, 2010, our outstanding equity consisted of 64,575,065 Class A Units and 39,997 Class B Units. Additionally, 6,949,004 Waiver Units were outstanding.

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, until December 2010, to our general partner. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves.

Until December 2010, our general partner received incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds, in addition to its 2% general partner interest. We paid distributions in 2009 and 2010 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 2008	February 2009	$	0.3300	$	13,021	$	266	$	823	$	14,110
First quarter 2009	May 2009	$	0.3375	$	13,317	$	271	$	1,125	$	14,713
Second quarter 2009	August 2009	$	0.3450	$	13,621	$	278	$	1,427	$	15,326
Third quarter 2009	November 2009	$	0.3525	$	13,918	$	284	$	1,729	$	15,931
Fourth quarter 2009	February 2010	$	0.3600	$	14,251	$	291	$	2,037	$	16,579
First quarter 2010	May 2010	$	0.3675	$	14,548	$	297	$	2,339	$	17,184
Second quarter 2010	August 2010	$	0.3750	$	14,845	$	303	$	2,642	$	17,790
Third quarter 2010	November 2010	$	0.3875	$	15,339	$	313	$	3,147	$	18,799
Fourth quarter 2010	February 2011	$	0.4000	$	25,846	$	-	$	-	$	25,846

Net Income (Loss) per Common Unit

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

F-23

	Year Ended December 31,
	2010			2009			2008
Numerators for basic and diluted net income per common unit:
(Loss) income attributable to Genesis Energy, L.P.	$	(48,459	)	$	8,063		$	26,089
Less: General partner's incentive distribution paid or to be paid for the period		(8,128	)		(6,318	)		(2,613	)
Add: Expense allocable to our general partner		76,923			18,853			-
Subtotal		20,336			20,598			23,476
Less: General partner 2% ownership		(407	)		(412	)		(470	)
Income available for common unitholders	$	19,929		$	20,186		$	23,006

Denominator for basic and diluted per common unit		40,560			39,471			38,961


Basic and diluted net income per common unit	$	0.49		$	0.51		$	0.59

Equity Issuances and Contributions

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.

In November 2010, we issued 5,175,000 common units in a public offering in connection with the acquisition of a 50% equity interest in Cameron Highway. The new common units issued to the public for cash were as follows:

Period			Purchaser of Common Units			Units				Gross Unit Price				Issuance Value				GP Contributions				Costs				Net Proceeds
November 2010			Public				5,175			$	23.580			$	122,027			$	2,490			$	(5,680	)		$	118,837

We issued new common units in the acquisitions of assets 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

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.

In 2010 and 2009, we recorded non-cash contributions of $76.9 million and $14.1 million, respectively from our general partner related to incentive compensation arrangements with our senior executives. As the purpose of incentive interest was to incentivize these individuals to grow the partnership, the expense was recognized as compensation by us and a capital contribution by our general partner. These amounts relate to arrangements representing an equity interest in our general partner for which our general partner did not seek reimbursement under our partnership agreement.

F-24

12. Business Segment Information

Our operations consist of three operating segments: (1) Pipeline Transportation – interstate, intrastate and offshore 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, and (3) Supply and Logistics – terminaling, blending, storing, marketing, gathering and transporting by truck and barge crude oil, petroleum products and certain industrial gases. Substantially all of our revenues are derived from, and substantially all of our assets are located in the United States. In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO2 marketing activities and processing of syngas through a joint venture, formerly reported in the Industrial Gases Segment, are now included in our Supply and Logistics Segment. The change in operating segments had no impact on our reportable units for goodwill purposes. The historical segment disclosures have been recast to be consistent with the current presentation.

We 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 equity-based compensation plans and the unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Segment margin 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.

F-25

	Pipeline Transportation (a)		Refinery Services			Supply &Logistics			Total
Year Ended December 31, 2010
Segment margin (b)	$	48,305	$	62,923		$	38,336		$	149,564

Capital expenditures (c)	$	333,557	$	1,433		$	1,740		$	336,730
Maintenance capital expenditures	$	522	$	1,433		$	901		$	2,856
Net fixed and other long-term assets (d)	$	604,572	$	400,164		$	221,932		$	1,226,668

Revenues:
External customers	$	45,367	$	158,456		$	1,897,501		$	2,101,324
Intersegment (e)		10,285		(7,396	)		(2,889	)		-
Total revenues of reportable segments	$	55,652	$	151,060		$	1,894,612		$	2,101,324

Year Ended December 31, 2009
Segment margin (b)	$	42,162	$	51,844		$	40,484		$	134,490

Capital expenditures (c)	$	3,043	$	2,572		$	23,581		$	29,196
Maintenance capital expenditures	$	1,281	$	1,246		$	1,899		$	4,426
Net fixed and other long-term assets (d)	$	279,574	$	409,556		$	269,753		$	958,883

Revenues:
External customers	$	44,461	$	147,240		$	1,243,659		$	1,435,360
Intersegment (e)		6,490		(5,875	)		(615	)		-
Total revenues of reportable segments	$	50,951	$	141,365		$	1,243,044		$	1,435,360

Year Ended December 31, 2008
Segment margin (b)	$	33,149	$	55,784		$	45,952		$	134,885

Capital expenditures (c)	$	262,200	$	5,490		$	120,982		$	388,672
Maintenance capital expenditures	$	719	$	1,881		$	1,854		$	4,454
Net fixed and other long-term assets (d)	$	285,773	$	434,956		$	289,818		$	1,010,547

Revenues:
External customers	$	39,051	$	233,871		$	1,868,762		$	2,141,684
Intersegment (e)		7,196		(8,497	)		1,301			-
Total revenues of reportable segments	$	46,247	$	225,374		$	1,870,063		$	2,141,684

(a)	The pipeline transportation segment includes the income from our investment in Cameron Highway.

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

F-26

	Year Ended December 31,
	2010			2009			2008

Segment margin	$	149,564		$	134,490		$	134,885
Corporate general and administrative expenses		(110,058	)		(36,475	)		(22,113	)
Depreciation, amortization and impairment		(53,557	)		(67,586	)		(71,370	)
Net loss on disposal of surplus assets		(12	)		(160	)		(29	)
Interest expense		(22,924	)		(13,660	)		(12,937	)
Non-cash expenses not included in segment margin		(4,479	)		(4,089	)		1,355
Other items excluded from income
affecting segment margin		(6,487	)		(3,262	)		(4,328	)
(Loss) income before income taxes	$	(47,953	)	$	9,258		$	25,463

(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 Pipeline Transportation segment include our investment in Cameron Highway totaling $329.7 million. Amounts for our Supply and Logistics segment include investments in equity investees totaling $13.7 million, $15.1 million and $14.5 million at December 31, 2010, 2009 and 2008, 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.

	Year Ended December 31,
	2010		2009		2008

Operations, general and administrative services provided by our general partner	$	47,035	$	50,417	$	51,872
Sales of CO2 to Sandhill		2,706		2,867		2,941
Petroleum products sales to Davison family businesses		1,081		757		1,261
Marine operating fuel and expenses provided by an affiliate of the Robertson Group		2,443		-		-
Petroleum products sales to an affiliate of the
Robertson Group		3,740		-		-
Truck transportation services provided to Denbury		182		3,167		3,578
Pipeline transportation services provided to Denbury		1,365		14,375		10,727
Payments received under direct financing leases from
Denbury		99		21,853		11,519
Pipeline transportation income portion of direct financing lease fees from Denbury		1,502		18,295		11,011
Pipeline monitoring services provided to Denbury		10		120		120
CO2 transportation services provided by Denbury		373		5,475		6,424
Crude oil purchases from Denbury		-		1,754		-

Until December 28, 2010, we did not directly employ any persons to manage or operate our business. Those functions were provided by our general partner. We reimbursed our general partner for all direct and indirect costs of these services, excluding any payments to our management team pursuant to their Class B or Series B ownership interests in our general partner. See Note 15.

F-27

Until February 5, 2010, Denbury owned our general partner. The items in this table include the amounts related to transactions with Denbury while Denbury was a related party. From February 5, 2010 until December 28, 2010, the Robertson Group controlled our general partner. On December 28, 2010, we acquired our general partner.

Additionally, on July 29, 2010, we acquired the 51% interest of TD Marine in DG Marine. See Note 3.

Amounts due to and from Related Parties

At December 31, 2010, an affiliate of the Robertson Group owed us $1.4 million, and we owed the affiliate $0.2 million. At December 31, 2010 and 2009, Sandhill owed us $0.2 million and $0.7 million for purchases of CO2, respectively.

At December 31, 2009 we owed Denbury $1.0 million, respectively, for CO2 transportation charges. Denbury owed us $1.9 million for transportation services at December 31, 2009. We owed our general partner $2.1 million for administrative services at December 31, 2009.

Financing

We guarantee 50% of the obligation of Sandhill to Community Trust Bank. At December 31, 2010, the total amount of Sandhill’s obligation to the bank was $2.2 million; therefore, our guarantee was for $1.1 million.

As discussed in Note 11, our general partner made capital contributions in order to maintain its capital account totaling $2.5 million, less than $0.1 million and $0.5 million in 2010, 2009 and 2008, respectively. In 2010 and 2009, we recorded a capital contribution from our general partner of $76.9 million and $14.1 million, respectively, related to compensation recognized for our executive management team. See Note 15.

14. Supplemental Cash Flow Information

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

F-28

	Year Ended December 31,
	2010			2009			2008
(Increase) decrease in:
Accounts receivable	$	(41,648	)	$	(7,979	)	$	61,126
Inventories		(16,870	)		(16,559	)		(5,557	)
Other current assets		(4,036	)		(2,712	)		(2,419	)
Increase (decrease) in:
Accounts payable		47,401			19,203			(58,224	)
Accrued liabilities		9,666			(1,522	)		3,812
Net changes in components of operating assets and liabilities	$	(5,487	)	$	(9,569	)	$	(1,262	)

Payments of interest and commitment fees were $25.1 million, $13.3 million and $11.3 million, during the years ended December 31, 2010, 2009 and 2008, respectively.

Cash paid for income taxes in during the years ended December 31, 2010, 2009 and 2008 was $2.4 million, $0.2 million and $2.4 million, respectively.

At December 31, 2010, 2009 and 2008, we had incurred liabilities for fixed and intangible asset additions totaling $2.6 million ($2.3 million consists of intangible assets additions related to our information technology systems upgrade project), $0.5 million and $1.7 million, respectively, that had not been paid at the end of the year and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” 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 in our Consolidated Statements of Cash Flows. The seller-financed consideration payments made in December 2008 and December 2009 are included in financing cash flows.

15. Employee Benefit Plans and Equity-Based Compensation Plans

Until December 28, 2010, we did not directly employ any of the persons responsible for managing or operating our activities.

In order to encourage long-term savings and to provide additional funds for retirement to its employees, we sponsor a profit-sharing and retirement savings plan. Under this plan, our matching contribution is calculated as an equal match of the first 6% of each employee’s annual pretax contribution. We 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 $2.7 million, $2.2 million, and $2.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.

We also provided certain health care and survivor benefits for our active employees. Our health care benefit programs are self-insured, with a catastrophic insurance policy to limit our costs. We plan to continue self-insuring these plans in the future. The expenses included in the Consolidated Statements of Operations for these benefits were $6.5 million, $6.2 million, and $6.8 million in 2010, 2009 and 2008, respectively.

2010 Long Term Incentive Plan

In the second quarter of 2010, we adopted the Genesis Energy, LLC 2010 Long-Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the awards of phantom units and distribution equivalent rights to members of our board of directors, and employees who provide services to us. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met. Distribution equivalent rights (“DERs”) are tandem rights to receive on a quarterly basis an amount of cash equal to the amount of distributions that would have been paid on the phantom units had they been limited partner units issued by us. The 2010 Plan is administered by the Governance, Compensation and Business Development Committee (the “G&C Committee”) of our board of directors.

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The G&C Committee (at its discretion) will designate participants in the 2010 Plan, 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. 62,927 phantom units with tandem DERs were awarded under the 2010 Plan during 2010. The weighted average grant date fair value of these awards was $20.64 per unit. The phantom units will vest on the third anniversary of the date of issuance.

The compensation cost associated with the phantom units is re-measured each reporting period based on the market value of our common units, and is recognized over the vesting period. The liability recorded for the estimated amount to be paid to the participants under the 2010 LTIP is adjusted to recognize changes in the estimated compensation cost and vesting. Management’s estimates of the fair value of these awards are adjusted for assumptions about expected forfeitures of units prior to vesting. Due to the positions of the small group of employees and non-employee directors who received these awards, we have assumed as of December 31, 2010 that there will be no forfeitures of these phantom units. At December 31, 2010, we estimate the fair value of these awards to be approximately $1.6 million, and we recorded $0.4 million of compensation expense for the year ended December 31, 2010 in general and administrative expenses. For the awards outstanding at December 31, 2010, the remaining cost will be recognized over a weighted average period of approximately three years.

2007 Long Term Incentive Plan

As a result of the sale of our general partner on February 5, 2010, all outstanding phantom units issued pursuant to our 2007 Long Term Incentive Plan vested. As a result of this acceleration of the vesting period, we recorded non-cash compensation expense of $0.5 million in the first quarter of 2010. In total, 123,857 phantom units vested. In 2009 and 2008, we recorded compensation expense of $1.0 million and $0.7 million related to this plan. This expense is primarily included in general and administrative expenses.

Stock Appreciation Rights Plan

Our stock appreciation rights plan is administered by our G&C Committee, 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 average 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. If our G&C 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 our G&C 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 accounting guidance, 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.

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The liability amount accrued on the balance sheet is adjusted to the fair value of the outstanding awards at each balance sheet date with the adjustment reflected in the Consolidated Statement of Operations. The fair value is adjusted for expected forfeitures of rights (due to terminations before vesting, or expirations after vesting).

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, 2010	December 31, 2009	December 31, 2008
Expected life of rights (in years)	0.00 - 4.41	0.25 - 5.50	1.25 - 6.00
Risk-free interest rate	0.12% - 1.73%	0.05% - 2.52%	0.57% - 1.71%
Expected unit price volatility	41.9%	43.8%	42.8%
Expected future distribution yield	6.00%	8.50%	6.00%

The following table reflects rights activity under our plan as of January 1, 2010, and changes during the year ended December 31, 2010:

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

Outstanding at January 1, 2010		1,119,998		$	17.14
Exercised during 2010		(159,435	)	$	13.39
Forfeited or expired during 2010		(46,873	)	$	19.95
Outstanding at December 31, 2010		913,690		$	17.65		6.6	$	8,158
Exercisable at December 31, 2010		625,479		$	17.64		6.1	$	5,622

The total intrinsic value of rights exercised during 2010, 2009 and 2008 was $1.3 million, $0.1 million and $0.4 million, respectively, which was paid in cash to the participants.

At December 31, 2010, there was $0.8 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, 2010 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, 2010, the remaining cost will be recognized over a weighted average period of approximately one year.

We recorded charges and credits related to our stock appreciation rights for three years ended December 31, 2010 as follows:

Expense (Credits to Expense) Related to Stock Appreciation Rights

Statement of Operations	2010		2009		2008
Supply and logistics operating costs	$	2,451	$	1,431	$	(997	)
Refinery services operating costs		703		325		23
Pipeline operating costs		572		360		(296	)
General and administrative expenses		1,493		1,263		(1,141	)
Total	$	5,219	$	3,379	$	(2,411	)

Series B Units

Pursuant to restricted unit agreements entered into with Genesis Energy, LLC, our general partner, on February 5, 2010, certain members of our management team received an aggregate of 767 Series B units in our general partner. These awards provided for the conversion of the Series B units into Series A units in our general partner on the seventh anniversary of the issuance date of the awards or at the time of certain events including a change in control of our general partner. As a result of the IDR Restructuring on December 28, 2010, the Series B units converted into Series A units. The Series A units were then exchanged for a total of 2,364,279 Class A Units and 827,484 Waiver Units. See Note 11 for a discussion of the IDR Restructuring and our equity securities.

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Although the Series B Units represented an equity interest in our general partner and our general partner did not seek reimbursement under our partnership agreement for the value of these compensation arrangements, we recorded non-cash expense for the estimated fair value of the awards. The estimated fair value of the converted Series B units was recomputed at each quarterly reporting date and at the date of conversion, and the expense we recorded was adjusted based on that fair value, with an offsetting entry to the capital account of our general partner. For the year ended December 31, 2010, we recorded non-cash expense of $79.1 million related to these Series B awards. As the awards are fully-vested, no further compensation expense for these awards remains to be recorded.

Pursuant to the IDR Restructuring, we are required to establish an equity incentive plan in 2011 for our eligible employees, including our executive officers, for the issuance of approximately 145,620 Class A Units and 50,967 Waiver Units. However, if unitholder approval is required for such plan and our Board determines not to seek such approval, which determination has not yet been made, we are required to establish a cash-settled or cash-based plan not subject to such approval that would provide substantially equivalent economic benefits to such participants as the equity incentive plan.

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. The Class B membership interests awarded to our senior executives were accounted for as liability awards under the guidance for equity-based compensation. As such, the fair value of the compensation cost we recorded for these awards was recomputed at each measurement date through final settlement and the expense to be recorded was adjusted based on that fair value.

All of the Class B membership interests in our general partner held by our management team at December 31, 2009 were either (i) converted into Series A units in our general partner or (ii) redeemed by our general partner on February 5, 2010. In total, the value of the Series A units issued and cash payments made by our general partner to settle its obligations under the Class B membership interests and related deferred compensation totaled $14.9 million. This value, when combined with amounts previously paid to our management team during 2009 related to the Class B membership interests, resulted in total compensation expense of $15.4 million. Upon settlement by our general partner of these arrangements with our management team, we recorded a reduction in expense of $2.1 million in the first quarter of 2010. In the year ended December 31, 2009, we recorded expense related to these arrangements of $14.1 million. No expense was required to be recorded in 2008 related to the Class B membership interests.

Bonus Program

In January 2011, our Board and G&C Committee approved a bonus program, referred to as the Bonus Plan, for all employees that is applicable to 2010. Bonuses under the Bonus Plan are paid at the discretion of our G&C Committee to our employees and executive officers.

In 2010, our G&C Committee based bonus amounts primarily on the amount of cash we generated for distributions to our unitholders, measured on a calendar-year basis. Two metrics were used to determine the general bonus pool – the level of Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generated and our company-wide safety record improvement which included a targeted reduction in our company-wide incident injury rate. The level of Available Cash before Reserves generated for the year as a percentage of a target set by our G&C Committee is weighted 90% and the achieved level of the targeted improvement in our safety record is weighted 10%. The sum of the weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages established by our G&C Committee for the various levels of our employees to determine the maximum general bonus pool.

For 2010, we accrued $5.0 million for estimated bonuses to be paid pursuant to the Bonus Plan. In 2009 and 2008, we had in place a bonus program similar to the Bonus Plan and we paid bonuses totaling $3.9 million and $4.5 million to our executive officers and employees. 2010 bonuses will be paid to employees in March 2011.

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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 13%, 12.5% and 14.6% of total revenues in 2010, 2009 and 2008, respectively. The revenues from Shell Oil Company in all three years relate primarily to our supply and logistics operations.

17. Derivatives

Commodity Derivatives

We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity prices, primarily crude oil, fuel oil and petroleum products; however, only a portion of these instruments are designated as hedges under the accounting guidance. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and natural gas futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed.

We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Consolidated Statements of Operations.

In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Other current assets in our Consolidated Balance Sheets.

At December 31, 2010, we had the following outstanding derivative commodity futures, forwards and options contracts that were entered into to hedge inventory or fixed price purchase commitments:

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	Sell (Short)		Buy (Long)
	Contracts		Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		28		-
Weighted average contract price per bbl	$	85.49	$	-

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		537		260
Weighted average contract price per bbl	$	89.85	$	90.17

Heating oil futures:
Contract volumes (1,000 bbls)		207		-
Weighted average contract price per gal	$	2.52	$	-

RBOB gasoline futures:
Contract volumes (1,000 bbls)		9		-
Weighted average contract price per gal	$	2.28	$	-

#6 Fuel Oil futures:
Contract volumes (1,000 bbls)		300		80
Weighted average contract price per bbl	$	76.34	$	76.33

Natural Gas:
Contract volumes (mmBtu)		5		-
Weighted average contract price per mmBtu	$	4.40	$	-

Crude oil written calls:
Contract volumes (1,000 bbls)		210		-
Weighted average premium received	$	1.97	$	-

Interest Rate Derivatives

Until July 29, 2010, DG Marine utilized swap contracts with financial institutions to hedge interest payments for its outstanding debt. DG Marine expected these interest rate swap contracts to be highly effective in limiting its exposure to fluctuations in market interest rates; therefore, we designated these swap contracts as cash flow hedges under accounting guidance. The effective portion of the derivative represented the change in fair value of the hedge that offset the change in cash flows of the hedged item. The effective portion of the gain or loss in the fair value of these swap contracts was reported as a component of AOCL and was reclassified into future earnings contemporaneously, as interest expense associated with the underlying debt under the DG Marine credit facility was recorded. In the third quarter of 2010, we settled the DG Marine interest rate swaps in connection with our acquisition of the 51% of DG Marine that we did not own. See Note 3.

Financial Statement Impacts

The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements.

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		Impact of Unrealized Gains and Losses
		Consolidated	Consolidated
Derivative Instrument	Hedged Risk	Balance Sheets	Statements of Operations
Designated as hedges under accounting guidance:
Crude oil futures contracts (fair value hedge)	Volatility in crude oil prices - effect on market value of inventory	Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories	Excess, if any, over effective portion of hedge is recorded in Supply and logistics costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged

Interest rate swaps (cash flow hedge) (through July 2010)	Changes in interest rates	Entire hedge is recorded in Accrued liabilities or Other long-term liabilities depending on duration	Expect hedge to fully offset hedged risk; no ineffectiveness recorded. Effective portion is recorded to AOCL and ultimately reclassified to Interest expense

Not qualifying or not designated as hedges under accounting guidance:
Commodity hedges consisting of crude oil, heating oil and natural gas futures and forward contracts and call options	Volatility in crude oil and petroleum products prices - effect on market value of inventory or purchase commitments	Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities	Entire amount of change in fair value of derivative is recorded in Supply and logistics costs - product costs

Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. Additionally, the offsetting change in the fair value of inventory that is recorded for our fair value hedges is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities.

The following tables reflect the estimated fair value gain (loss) position of our hedge derivatives and related inventory impact for qualifying hedges at December 31, 2010 and 2009:

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Fair Value of Derivative Assets and Liabilities

	Asset Derivatives
	Consolidated Balance Sheets Location
		Fair Value
		December 31, 2010			December 31, 2009
Commodity derivatives - futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other current assets	$	14		$	53
Undesignated hedges	Other current assets		493			307
Total asset derivatives		$	507		$	360


	Liability Derivatives
	Consolidated Balance Sheets Location
		Fair Value
		December 31, 2010			December 31, 2009
Commodity derivatives - futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other current assets	$	(191	) (1)	$	(159	)
Undesignated hedges	Other current assets		(2,283	) (1)		(2,118	)
Total commodity derivatives			(2,474	)		(2,277	)

Interest rate swaps designated as cash flow hedges under accounting rules:
Portion expected to be reclassified into earnings within one year	Accrued liabilities		-			(1,176	)
Portion expected to be reclassified into earnings after one year	Other long-term liabilities		-			(512	)

Total liability derivatives		$	(2,474	)	$	(3,965	)

(1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets in Other current assets.

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	Effect on Consolidated Statements of Operations
	and Other Comprehensive Loss
	Amount of Gain (Loss) Recognized in Income
	Supply & Logistics						Interest Expense						Other Comprehensive Loss
	Product Costs						Reclassified from AOCL						Effective Portion
	Year Ended						Year Ended						Year Ended
	December 31,						December 31,						December 31,
	2010			2009			2010			2009			2010			2009
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	$	307	(1)	$	(5,321	) (1)	$	-		$	-		$	-		$	-
Contracts not considered hedges under accounting guidance		(4	)		(2,446	)		-			-			-			-
Total commodity derivatives		303			(7,767	)		-			-			-			-

Interest rate swaps designated as cash flow hedges under accounting guidance		-			-			(2,112	)		(784	)		(424	)		(508	)

Total derivatives	$	303		$	(7,767	)	$	(2,112	)	$	(784	)	$	(424	)	$	(508	)

(1) Represents the amount of gain (loss) recognized in income for derivatives related to the fair value hedge of inventory. The amount excludes the gain on the hedged inventory under the fair value hedge of $1.0 million and $7.5 million for the year ended 2010 and 2009, respectively.

We have no derivative contracts with credit contingent features.

18. Fair-Value Measurements

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, 2010 and 2009. As required by fair value accounting guidance, 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, 2010							Fair Value at December 31, 2009
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives :
Assets	$	507		$	-	$	-	$	360		$	-	$	-
Liabilities	$	(2,474	)	$	-	$	-	$	(2,277	)	$	-	$	-

Interest rate swaps	$	-		$	-	$	-	$	-		$	-	$	(1,688	)

Level 1

Included in Level 1 of the fair value hierarchy as 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 2

At December 31, 2010 and 2009, we had no Level 2 fair value measurements.

Level 3

At December 31, 2010, we had no Level 3 fair value measurements. Included within Level 3 of the fair value hierarchy at December 31, 2009 were our interest rate swaps. These swaps were settled in July 2010 in connection with the acquisition of the 51% of DG Marine we did not own and the termination of DG Marine’s credit facility. See Note 3.

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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,
	2010			2009
Balance at beginning of period	$	(1,688	)	$	(1,964	)
Realized and unrealized gains (losses)-
Reclassified into interest expense for settled contracts		2,112			784
Included in other comprehensive income		(424	)		(508	)
Balance at end of period	$	-		$	(1,688	)

Total amount of losses for the year ended included in earnings attributable to the change in unrealized losses relating to liabilities still held at December 31, 2010 and 2009, respectively	$	-		$	(10	)

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 and (2) valuing potential impairment loss related to long-lived assets.

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 2011 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, 2010, were as follows (in thousands).

	Office		Transportation		Terminals and
	Space		Equipment		Tanks		Total

2011	$	901	$	3,510	$	6,875	$	11,286
2012		777		2,152		4,897		7,826
2013		735		1,432		1,577		3,744
2014		731		1,243		1,027		3,001
2015		741		732		1,027		2,500
2016 and thereafter		62		1,239		20,109		21,410
Total minimum lease obligations	$	3,947	$	10,308	$	35,512	$	49,767

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

Year ended December 31, 2010	$	15,692
Year ended December 31, 2009	$	12,023
Year ended December 31, 2008	$	8,757

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 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, 2010, Sandhill owed $2.2 million; therefore our guarantee was $1.1 million. 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. In May 2006, the State of Texas enacted a law which requires us to pay a tax of 0.5% on our “margin,” as defined in the law. The “margin” to which the tax rate is applied generally is 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.

Our income tax expense (benefit) is as follows:

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	Year Ended December 31,
	2010			2009		2008
Current:
Federal	$	1,664		$	1,458	$	2,979
State		1,494			1,442		872
Total current income tax expense		3,158			2,900		3,851

Deferred:
Federal		(573	)		168		(3,850	)
State		3			12		(363	)
Total deferred income tax (benefit) expense		(570	)		180		(4,213	)
Total income tax expense (benefit)	$	2,588		$	3,080	$	(362	)

Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the balance sheet date. Deferred tax assets and liabilities consist of the following:

	December 31,
	2010			2009
Deferred tax assets:
Current:
Other current assets	$	445		$	279
Other		8			8
Total current deferred tax asset		453			287
Net operating loss carryforwards		862			308
Total long-term deferred tax asset		862			308
Valuation allowances		(416	)		(308	)
Total deferred tax assets		899			287

Deferred tax liabilities:
Current:
Other		(213	)		(198	)
Long-term:
Fixed assets		(7,807	)		(8,481	)
Intangible assets		(7,386	)		(6,686	)
Total long-term liability		(15,193	)		(15,167	)
Total deferred tax liabilities		(15,406	)		(15,365	)

Total net deferred tax liability	$	(14,507	)	$	(15,078	)

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for state net operating loss carryforwards.

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

F-40

	Year Ended December 31,
	2010			2009			2008

(Loss) income before income taxes	$	(47,953	)	$	9,258		$	25,463
Partnership loss (income) not subject to tax		47,357			(7,822	)		(30,902	)
(Loss) income subject to income taxes		(596	)		1,436			(5,439	)

Tax (benefit) expense at federal statutory rate	$	(209	)	$	503		$	(1,904	)
State income taxes, net of federal benefit		583			991			357
Effects of unrecognized tax positions, federal and state		1,909			1,733			1,431
Return to provision, federal and state		257			(224	)		(258	)
Other		48			77			12
Income tax expense (benefit)	$	2,588		$	3,080		$	(362	)

Effective tax rate on (loss) income before income taxes		(1	)		33	%		-1	%

(1) Income tax expense is related to taxable income generated by our corporate subsidiaries and Texas Margin Tax. Due to the loss before income taxes in 2010, the effective tax rate as a percentage of our total loss before income taxes is not meaningful.

The company adopted the provisions in accounting guidance related to uncertain tax positions on January 1, 2007. A reconciliation of the beginning and ending amount of our unrecognized tax positions, which is recorded in Other current liabilities on our Consolidated Balance Sheets was as follows:

Balance at January 1, 2008	$	864
Additions based on tax positions related to current year		1,735
Balance at December 31, 2008		2,599
Additions based on tax positions related to current year		1,733
Balance at December 31, 2009		4,332
Additions based on tax positions related to current year		1,909
Balance at December 31, 2010	$	6,241

If the unrecognized tax positions at December 31, 2010 were recognized, $6.2 million would affect our effective income tax rate. There are no uncertain tax positions as of December 31, 2010 for which it is reasonably possible that the amount of unrecognized tax positions would significantly decrease during 2011.

F-41

21. Quarterly Financial Data (Unaudited)

The table below summarizes our unaudited quarterly financial data for 2010 and 2009.

	2010 Quarters									Total
	First		Second		Third		Fourth (2)			Year
Revenues	$	466,531	$	456,538	$	576,012	$	602,243		$	2,101,324
Operating income (loss)	$	10,038	$	18,299	$	10,183	$	(65,904	)	$	(27,384	)
Net income (loss)	$	6,325	$	13,921	$	3,863	$	(74,650	)	$	(50,541	)
Net income (loss) attributable to
Genesis Energy, L.P.	$	6,885	$	14,238	$	5,068	$	(74,650	)	$	(48,459	)
Net income per common unit - basic and diluted	$	0.06	$	0.29	$	0.12	$	0.02		$	0.49

Cash distributions per common unit (1)	$	0.3600	$	0.3675	$	0.3750	$	0.3875		$	1.4900

	2009 Quarters									Total
	First		Second		Third		Fourth (2)			Year
Revenues	$	253,493	$	342,204	$	403,389	$	436,274		$	1,435,360
Operating income (loss)	$	7,021	$	7,748	$	8,356	$	(1,754	)	$	21,371
Net income (loss)	$	5,301	$	3,822	$	3,897	$	(6,842	)	$	6,178
Net income (loss) attributable to
Genesis Energy, L.P.	$	5,290	$	4,456	$	4,299	$	(5,982	)	$	8,063
Net income per common unit - basic and diluted	$	0.16	$	0.13	$	0.14	$	0.08		$	0.51

Cash distributions per common unit (1)	$	0.3300	$	0.3375	$	0.3450	$	0.3525		$	1.3650

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

(2) Includes executive compensation expense related to Series B and Class B awards borne entirely by our general partner in the amounts of $75.6 million for 2010 and $6.5 million for 2009. See Note 15.

22. Condensed Consolidating Financial Information

The $250 million Senior Unsecured Notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 10 for additional information regarding our consolidated debt obligations.

As a result of the IDR Restructuring on December 28, 2010 (see Note 11), each subsidiary guarantor and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P.

The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors:

F-42

	December 31, 2010
	Genesis Energy, L.P. (Parent and		Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)		(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1	$	-	$	5,082		$	679		$	-		$	5,762
Other current assets		584,967		-		245,240			20,620			(604,051	)		246,776
Total current assets		584,968		-		250,322			21,299			(604,051	)		252,538
Fixed Assets, at cost		-		-		297,832			75,507			-			373,339
Less: Accumulated depreciation		-		-		(101,472	)		(6,811	)		-			(108,283	)
Net fixed assets		-		-		196,360			68,696			-			265,056
Goodwill		-		-		325,046			-			-			325,046
Other assets, net		14,695		-		310,808			166,616			(171,458	)		320,661
Equity investees and other investments		-		-		343,434			-			-			343,434
Investments in subsidiaries		682,641		-		83,323			-			(765,964	)		-
Total assets	$	1,282,304	$	-	$	1,509,293		$	256,611		$	(1,541,473	)	$	1,506,735

LIABILITIES AND PARTNERS' CAPITAL
Current liabiltiies	$	3,040	$	-	$	805,381		$	2,172		$	(603,879	)	$	206,714
Senior secured credit facilities		360,000		-		-			-			-			360,000
Senior unsecured notes		250,000		-		-			-			-			250,000
Deferred tax liabilities		-		-		15,193			-			-			15,193
Other liabilities		-		-		5,564			171,266			(171,266	)		5,564
Total liabilities		613,040		-		826,138			173,438			(775,145	)		837,471
Partners' capital		669,264		-		683,155			83,173			(766,328	)		669,264
Total liabilities and partners' capital	$	1,282,304	$	-	$	1,509,293		$	256,611		$	(1,541,473	)	$	1,506,735

F-43

	December 31, 2009

	Genesis Energy, L.P. (Parent and		Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)*		(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	-	$	3,884		$	262		$	-		$	4,148
Other current assets		92		-		181,400			11,410			(7,806	)		185,096
Total current assets		94		-		185,284			11,672			(7,806	)		189,244
Fixed Assets, at cost		-		-		298,459			75,468			-			373,927
Less: Accumulated depreciation		-		-		(84,829	)		(4,211	)		-			(89,040	)
Net fixed assets		-		-		213,630			71,257			-			284,887
Goodwill		-		-		325,046			-			-			325,046
Other assets, net		-		-		338,085			170,526			(174,789	)		333,822
Equity investees and other investments		-		-		15,128			-			-			15,128
Investments in subsidiaries		595,783		-		76,148			-			(671,931	)		-
Total assets	$	595,877	$	-	$	1,153,321		$	253,455		$	(854,526	)	$	1,148,127

LIABILITIES AND PARTNERS' CAPITAL
Current liabiltiies	$	-	$	-	$	146,398		$	2,894		$	(7,864	)	$	141,428
Senior secured credit facilities		-		-		366,900			-			-			366,900
Deferred tax liabilities		-		-		15,167			-			-			15,167
Other liabilities		-		-		5,699			174,593			(174,593	)		5,699
Total liabilities		-		-		534,164			177,487			(182,457	)		529,194
Partners' capital		595,877		-		596,666			75,968			(672,634	)		595,877
Non-controlling interests		-		-		22,491			-			565			23,056
Total partners' capital		595,877		-		619,157			75,968			(672,069	)		618,933
Total liabilities and partners' capital	$	595,877	$	-	$	1,153,321		$	253,455		$	(854,526	)	$	1,148,127

*The Company previously reported the investments in subsidiaries as $628.6 million and partners’ capital as $628.6 million for Genesis Energy, L.P. (Parent and Co-Issuer) at December 31, 2009. This presentation was in error and has been corrected resulting in the presentation of such Parent company amounts as shown above.

F-44

	Year Ended December 31, 2010
	Genesis Energy, L.P. (Parent and			Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)			(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated
REVENUES:
Supply and logistics	$	-		$	-	$	1,894,612		$	-		$	-		$	1,894,612
Refinery services		-			-		146,570			14,544			(10,054	)		151,060
Pipeline transportation services		-			-		29,497			26,155			-			55,652
Total revenues		-			-		2,070,679			40,699			(10,054	)		2,101,324

COSTS AND EXPENSES:
Supply and logistics costs		-			-		1,858,862			-			-			1,858,862
Refinery services operating costs		-			-		85,250			12,672			(9,828	)		88,094
Pipeline transportation operating costs		-			-		14,301			476			-			14,777
General and administrative		-			-		113,406			-			-			113,406
Depreciation and amortization		-			-		50,961			2,596			-			53,557
Net loss on disposal of surplus assets		-			-		12			-			-			12
Total costs and expenses		-			-		2,122,792			15,744			(9,828	)		2,128,708
OPERATING (LOSS) INCOME		-			-		(52,113	)		24,955			(226	)		(27,384	)
Equity in earnings of joint ventures		-			-		2,355			-			-			2,355
Equity in earnings of subsidiaries		(34,988	)				7,401						27,587			-
Interest (expense) income, net		(13,471	)		-		7,884			(17,337	)		-			(22,924	)
(Loss) income before income taxes		(48,459	)		-		(34,473	)		7,618			27,361			(47,953	)
Income tax (expense) benefit		-			-		(2,175	)		(413	)		-			(2,588	)
NET (LOSS) INCOME		(48,459	)		-		(36,648	)		7,205			27,361			(50,541	)
Net loss attributable to noncontrolling interests		-			-		2,083			-			(1	)		2,082
NET (LOSS) INCOME ATTRIBUTABLE TO
GENESIS ENERGY, L.P.	$	(48,459	)	$	-	$	(34,565	)	$	7,205		$	27,360		$	(48,459	)

F-45

	Year Ended December 31, 2009
	Genesis Energy, L.P. (Parent and		Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)		(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated
REVENUES:
Supply and logistics	$	-	$	-	$	1,243,044		$	-		$	-		$	1,243,044
Refinery services		-		-		138,438			9,527			(6,600	)		141,365
Pipeline transportation services		-		-		25,004			25,947			-			50,951
Total revenues		-		-		1,406,486			35,474			(6,600	)		1,435,360

COSTS AND EXPENSES:
Supply and logistics costs		-		-		1,203,896			-			-			1,203,896
Refinery services operating costs		-		-		86,346			9,320			(6,756	)		88,910
Pipeline transportation operating costs		-		-		12,542			482			-			13,024
General and administrative		-		-		40,402			11			-			40,413
Depreciation and amortization		-		-		59,992			2,589			-			62,581
Net loss on disposal of surplus assets		-		-		160			-			-			160
Impairment expense		-		-		5,005			-			-			5,005
Total costs and expenses		-		-		1,408,343			12,402			(6,756	)		1,413,989
OPERATING (LOSS) INCOME		-		-		(1,857	)		23,072			156			21,371
Equity in earnings of joint ventures		-		-		1,547			-			-			1,547
Equity in earnings of subsidiaries		8,063				5,614			-			(13,677	)		-
Interest income (expense), net		-		-		3,998			(17,658	)		-			(13,660	)
Income (loss) before income taxes		8,063		-		9,302			5,414			(13,521	)		9,258
Income tax expense		-		-		(3,080	)		-			-			(3,080	)
NET INCOME (LOSS)		8,063		-		6,222			5,414			(13,521	)		6,178
Net loss attributable to noncontrolling interests		-		-		1,885			-			-			1,885
NET INCOME (LOSS) ATTRIBUTABLE TO
GENESIS ENERGY, L.P.	$	8,063	$	-	$	8,107		$	5,414		$	(13,521	)	$	8,063

F-46

	Year Ended December 31, 2008
	Genesis Energy, L.P. (Parent and		Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)		(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated
REVENUES:
Supply and logistics	$	-	$	-	$	1,870,063		$	-		$	-		$	1,870,063
Refinery services		-		-		219,396			6,167			(189	)		225,374
Pipeline transportation services		-		-		30,817			15,430			-			46,247
Total revenues		-		-		2,120,276			21,597			(189	)		2,141,684

COSTS AND EXPENSES:
Supply and logistics costs		-		-		1,821,574			-			-			1,821,574
Refinery services operating costs		-		-		159,889			6,207			-			166,096
Pipeline transportation operating costs		-		-		14,945			279			-			15,224
General and administrative		-		-		29,490			10			-			29,500
Depreciation and amortization		-		-		69,823			1,547			-			71,370
Net loss on disposal of surplus assets		-		-		29			-			-			29
Total costs and expenses		-		-		2,095,750			8,043			-			2,103,793
OPERATING INCOME (LOSS)		-		-		24,526			13,554			(189	)		37,891
Equity in earnings of joint ventures		-		-		509			-			-			509
Equity in earnings of subsidiaries		26,089				3,238			-			(29,327	)		-
Interest expense		-		-		(2,503	)		(10,434	)		-			(12,937	)
Income (loss) before income taxes		26,089		-		25,770			3,120			(29,516	)		25,463
Income tax (expense) benefit		-		-		362			-			-			362
NET INCOME (LOSS)		26,089		-		26,132			3,120			(29,516	)		25,825
Net loss attributable to noncontrolling interests		-		-		265			-			(1	)		264
NET INCOME (LOSS) ATTRIBUTABLE TO
GENESIS ENERGY, L.P.	$	26,089	$	-	$	26,397		$	3,120		$	(29,517	)	$	26,089

F-47

	Year Ended December 31, 2010
	Genesis Energy, L.P. (Parent and			Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)			(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	(569,824	)	$	-	$	680,974		$	3,746		$	(24,433	)	$	90,463

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		-			-		(12,372	)		(28	)		-			(12,400	)
Distributions from joint ventures - return of investment		45,889			-		2,859			-			(45,889	)		2,859
Investments in joint ventures and other investments		(118,875	)		-		(332,462	)		-			118,875			(332,462	)
Repayments on loan to non-guarantor subsidiary		-			-		3,331			-			(3,331	)		-
Other, net		-			-		1,265			-			-			1,265
Net cash used in investing activities		(72,986	)		-		(337,379	)		(28	)		69,655			(340,738	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		449,729			-		242,100			-			-			691,829
Bank repayments		(455,629	)		-		(243,100	)		-			-			(698,729	)
Transfer of senior secured credit facility to Parent		364,772			-		(364,772	)		-			-			-
Proceeds from issuance of senior unsecured notes		250,000			-		-			-			-			250,000
Credit facility and senior unsecured notes issuance fees		(14,586	)		-		-			-			-			(14,586	)
Issuance of ownership interests to partners for cash		118,875			-		118,888			-			(118,888	)		118,875
Noncontrolling interests contributions, net of distributions		-			-		-			-			6			6
Acquisition of noncontrolling interest in DG Marine		-			-		(26,288	)		-			-			(26,288	)
Distributions to partners/owners		(70,352	)		-		(70,359	)		-			70,359			(70,352	)
Other, net		-			-		1,134			(3,301	)		3,301			1,134
Net cash provided by (used in) financing activities		642,809			-		(342,397	)		(3,301	)		(45,222	)		251,889

Net increase (decrease) in cash and cash equivalents		(1	)		-		1,198			417			-			1,614
Cash and cash equivalents at beginning of period		2			-		3,884			262			-			4,148
Cash and cash equivalents at end of period	$	1		$	-	$	5,082		$	679		$	-		$	5,762

F-48

	Year Ended December 31, 2009
	Genesis Energy, L.P. (Parent and			Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)			(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	(1	)	$	-	$	86,926		$	11,128		$	(7,974	)	$	90,079

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		-			-		(30,270	)		(62	)		-			(30,332	)
Distributions from joint ventures - return of investment		60,080			-		-			-			(60,080	)		0
Investments in joint ventures and other investments		(9	)		-		(83	)		-			9			(83	)
Repayments on loan to non-guarantor subsidiary		-			-		3,010			-			(3,010	)		-
Other, net		-			-		1,182			-			-			1,182
Net cash used in investing activities		60,071			-		(26,161	)		(62	)		(63,081	)		(29,233	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		-			-		255,300			-			-			255,300
Bank repayments		-			-		(263,700	)		-			-			(263,700	)
Credit facility and senior unsecured notes issuance fees		-			-		(422	)		-			-			(422	)
Issuance of ownership interests to partners for cash		9			-		9			-			(9	)		9
Noncontrolling interests contributions, net of distributions		-			-		-			-			(6	)		(6	)
Distributions to partners/owners		(60,080	)		-		(60,086	)		(8,000	)		68,086			(60,080	)
Other, net		-			-		(6,784	)		(2,984	)		2,984			(6,784	)
Net cash provided by (used in) financing activities		(60,071	)		-		(75,683	)		(10,984	)		71,055			(75,683	)

Net increase (decrease) in cash and cash equivalents		(1	)		-		(14,918	)		82			-			(14,837	)
Cash and cash equivalents at beginning of period		3			-		18,802			180			-			18,985
Cash and cash equivalents at end of period	$	2		$	-	$	3,884		$	262		$	-		$	4,148

F-49

	Year Ended December 31, 2008
	Genesis Energy, L.P. (Parent and			Genesis Energy Finance Corporation		Guarantor			Non-Guarantor						Genesis Energy, L.P.
	Co-Issuer)			(Co-Issuer)		Subsidiaries			Subsidiaries			Eliminations			Consolidated

Net cash provided by operating activities	$	(7	)	$	-	$	93,622		$	2,677		$	(1,484	)	$	94,808

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		-			-		(40,086	)		(226,159	)		-			(266,245	)
Distributions from investees - return of investment		50,534			-		886			-			(50,534	)		886
Investments in joint ventures and other investments		(511	)		-		(52,397	)		-			50,511			(2,397	)
Acquisition of Grifco assets		-			-		(66,686	)		-			-			(66,686	)
Loan to non-guarantor subsidiary, net of repayments		-			-		(175,101	)		-			175,101			-
Other, net		-			-		718			-			-			718
Net cash used in investing activities		50,023			-		(332,666	)		(226,159	)		175,078			(333,724	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		-			-		531,712			-			-			531,712
Bank repayments		-			-		(236,412	)		-			-			(236,412	)
Credit facility and senior unsecured notes issuance fees		-			-		(2,255	)		-			-			(2,255	)
Issuance of ownership interests to partners for cash		511			-		516			50,000			(50,516	)		511
Redemption of common units for cash		-			-		(16,667	)		-			-			(16,667	)
Noncontrolling interests contributions, net of distributions		-			-		25,500			-			-			25,500
Distributions to partners/owners		(50,534	)		-		(50,539	)		-			50,539			(50,534	)
Loan from parent, net of repayments		-			-		-			173,617			(173,617	)		-
Other, net		-			-		(5,805	)		-			-			(5,805	)
Net cash provided by (used in) financing activities		(50,023	)		-		246,050			223,617			(173,594	)		246,050

Net increase (decrease) in cash and cash equivalents		(7	)		-		7,006			135			-			7,134
Cash and cash equivalents at beginning of period		10			-		11,796			45			-			11,851
Cash and cash equivalents at end of period	$	3		$	-	$	18,802		$	180		$	-		$	18,985

F-50

Financial Statements of Significant Equity Investee – Cameron Highway Oil Pipeline Company

INDEPENDENT AUDITORS’ REPORT

To the Management Committee of

Cameron Highway Oil Pipeline Company

Houston, Texas

We have audited the accompanying balance sheet of Cameron Highway Oil Pipeline Company (the “Company”) as of December 31, 2010, and the related statements of operations, partners’ equity, and cash flows for the period from November 23, 2010 through December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2010, and the results of its operations and its cash flows for the period from November 23, 2010 through December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 4, 2011

F-51

CAMERON HIGHWAY OIL PIPELINE COMPANY

BALANCE SHEET

December 31, 2010

(Dollars in thousands)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,587
Accounts receivable – trade		8,172
Accounts receivable – affiliates		218
Prepaid and other current assets		918
Total current assets		11,895
PROPERTY, PLANT AND EQUIPMENT, NET		455,424
Total assets	$	467,319

LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable – trade	$	2,420
Accounts payable – affiliates		1,525
Other current liabilities		657
Total current liabilities		4,602
OTHER LIABILITIES		1,475
COMMITMENTS AND CONTINGENCIES
PARTNERS’ EQUITY		461,242
Total liabilities and partners’ equity	$	467,319

See Notes to Financial Statements

F-52

CAMERON HIGHWAY OIL PIPELINE COMPANY

STATEMENT OF OPERATIONS

Period from November 23, 2010 through December 31, 2010

(Dollars in thousands)


REVENUES
Crude oil handling revenues	$	5,636
Total revenues		5,636
COSTS AND EXPENSES
Depreciation and accretion		1,797
Other operating costs and expenses (see Note 5)		1,159
General and administrative costs		16
Total costs and expenses		2,972
NET INCOME	$	2,664

See Notes to Financial Statements

F-53

CAMERON HIGHWAY OIL PIPELINE COMPANY

STATEMENT OF CASH FLOWS

Period from November 23, 2010 through December 31, 2010

(Dollars in thousands)

OPERATING ACTIVITIES
Net income	$	2,664
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and accretion		1,797
Effect of changes in operating accounts
Accounts receivable		129
Prepaid and other current assets		100
Accounts payable		388
Other current liabilities		(27	)
Net cash provided by operating activities		5,051
INVESTING ACTIVITIES
Capital expenditures		(104	)
Cash used in investing activities		(104	)
FINANCING ACTIVITIES
Distributions to partners		(7,800	)
Cash used in financing activities		(7,800	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(2,853	)
CASH AND CASH EQUIVALENTS, NOVEMBER 23		5,440
CASH AND CASH EQUIVALENTS, DECEMBER 31	$	2,587

See Notes to Financial Statements

F-54

CAMERON HIGHWAY OIL PIPELINE COMPANY

STATEMENT OF PARTNERS’ EQUITY

Period from November 23, 2010 through December 31, 2010

(Dollars in thousands)

	Cameron Highway			Cameron Highway			Cameron Highway
	Pipeline I, L.P.			Pipeline II, L.P.			Pipeline III, L.P.
	(Enterprise)			(Genesis)			(Genesis)
	50%			25%			25%			Total
BALANCE AT NOVEMBER 23, 2010	$	233,188		$	116,595		$	116,595		$	466,378
Net income		1,332			666			666			2,664
Distributions to partners		(3,900	)		(1,950	)		(1,950	)		(7,800	)
BALANCE AT DECEMBER 31, 2010	$	230,620		$	115,311		$	115,311		$	461,242

See Notes to Financial Statements

F-55

CAMERON HIGHWAY OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

1. Partnership Organization

Cameron Highway Oil Pipeline Company (“Cameron Highway”) is a Delaware general partnership formed in June 2003 to construct, install, own and operate a 374-mile crude oil pipeline (the “Pipeline”) located in deepwater areas of the central Gulf of Mexico offshore Texas and Louisiana. Unless the context requires otherwise, references to “we,” “us”, “our” or the “Company,” within these notes are intended to mean the Cameron Highway joint venture.

At December 31, 2010, we were owned (i) 50% by Cameron Highway Pipeline I, L.P. (“CHOPS I”), a subsidiary of Enterprise GTM Holdings L.P. (“Enterprise”), (ii) 25% by Cameron Highway Pipeline II, L.P. (“CHOPS II”), a subsidiary of Genesis Energy, L.P. (“Genesis”), and (iii) 25% by Cameron Highway Pipeline III, L.P. (“CHOPS III”), another subsidiary of Genesis. CHOPS I, CHOPS II and CHOPS III are collectively referred to as the “Partners.” Genesis acquired its indirect 50% equity interest in Cameron Highway from Valero Energy Corporation on November 23, 2010.

2. Summary of Significant Accounting Policies

Our financial statements are prepared on the accrual basis of accounting in conformity with U.S. generally accepted accounting principles (“GAAP”). Except as noted within the context of each footnote disclosure, dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Business Segment

We operate in a single business segment, Offshore Pipeline & Services, which consists of a 374-mile pipeline used in the transportation of crude oil.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Our Statements of Cash Flows are prepared using the indirect method.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Crude Oil Imbalances

F-56

Crude oil imbalances arise in the course of providing crude oil handling services, where we receive volumes of crude oil that differ from the volumes committed to be redelivered. These differences result in imbalances that are settled in-kind (i.e., with crude oil volumes instead of cash) the following month. We value our crude oil imbalances using contractual settlement prices. Imbalance receivables and payables are classified on our balance sheet within accounts receivable and payable, respectively. At December 31, 2010, our imbalance receivables were $0.3 million, and our imbalance payables were $0.5 million.

Environmental Costs

Our operations include activities subject to federal and state environmental regulations. Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. There were no environmental remediation liabilities incurred as of December 31, 2010.

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Any future changes in facts and circumstances may require updated estimates, which, in turn, could have a significant impact on our financial statements.

Financial Instruments

Cash and cash equivalents, accounts receivable and accounts payable are carried at amounts which reasonably approximate their fair values due to their short-term nature.

Impairment Testing For Long-Lived Assets

Long-lived assets such as property, plant and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if the carrying value exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. No asset impairment charges were recognized for any of the periods presented.

Income Taxes

We are organized as a pass-through entity for federal income tax purposes and our Partners are individually responsible for their allocable share of our taxable income for federal income tax purposes. As a result, our financial statements do not provide for such taxes.

F-57

Partnership Equity

We allocate income or loss and pay cash distributions to Partners in accordance with their respective partnership interests.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized. Minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. See Note 3 for additional information regarding our property, plant and equipment.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value (through accretion expense) and the capitalized cost is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 3 for additional information regarding our AROs.

Recently Issued Accounting Standards

The accounting standard setting organizations, including the U.S. Securities and Exchange Commission, have recently issued various new accounting standards. We have evaluated these new standards and have determined that the adoption of these rules will not have a material impact on us.

Revenue Recognition

Crude oil handling revenues are generated from purchase and sale arrangements whereby we purchase crude oil from shippers at various receipt points along the Pipeline for an index-based price (less a price differential) and sell the crude oil back to the same shippers at various redelivery points at the same index-based price. Since these are purchase and sales transactions with the same counterparty and are entered into in contemplation of one another, we recognize net revenue from such arrangements based upon the price differential per unit of volume (typically in barrels) multiplied by the volume delivered. We net the corresponding receivables and payables from such transactions on our balance sheet for consistency of presentation.

Subsequent Events

We have evaluated subsequent events through March 4, 2011, which is the date our Audited Financial Statements and Notes were available to be issued, and have determined that there were no material subsequent events.

F-58

3. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

	Estimated	December 31,
	Useful Life	2010
Pipeline (1)	30 years	$	329,093
Platforms and facilities (2)	30 years		169,789
Crude oil line fill (3)	n/a		34,053
Construction in progress	n/a		19,056
Total			551,991
Less accumulated depreciation			96,567
Property, plant and equipment, net		$	455,424

(1)

Includes the Pipeline and related assets.

(2)

Platforms and facilities include offshore platforms and related facilities that are an integral part of the Pipeline.

(3)

Crude oil line fill is carried at original cost and is not depreciated, but it is subject to impairment considerations.

The Pipeline has a throughput capacity of 500,000 barrels per day and is designed to gather production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon and Walker Ridge areas, for delivery to refineries and terminals in southeast Texas. The Pipeline is supported by life of lease dedications by BP, BHP Billiton Ltd. and Chevron in connection with their production from the Holstein, Mad Dog and Atlantis fields and by Anadarko in connection with its production from the Constitution and Ticonderoga fields. Additionally, we have contracted with Petrobras to transport crude oil production from the Cottonwood field.

Our AROs primarily result from right-of-way agreements associated with our pipeline operations and regulatory requirements triggered by the abandonment or retirement of certain offshore facilities. None of our assets are legally restricted for purposes of settling AROs.

Property, plant and equipment at December 31, 2010 includes $1.2 million of estimated ARO costs capitalized as an increase in the associated long-lived asset. Based on information currently available, we estimate that accretion expense will approximate $0.1 million annually for 2011 through 2014 and $0.2 million for 2015.

4. Related Party Transactions

We have an Operation and Management Agreement (the “Agreement”) with Manta Ray Offshore Gathering Co LLC (“Manta Ray”) for the operation and management of the Pipeline. Manta Ray is a subsidiary of Enterprise. Pursuant to the agreement, we pay Manta Ray $350,000 per month (adjusted annually for changes in an average weekly earnings index as defined in the Agreement) for routine operating services. During 2010, such amount was approximately $462,000 per month. We reimburse Manta Ray for all non-routine operations-related services.

The Agreement may be terminated or canceled by us if Manta Ray (i) defaults in the performance of any of its obligations; (ii) dissolves, liquidates or terminates its separate corporate existence; (iii) makes a general assignment for the benefit of creditors or admits in writing its inability to pay its debts; or (iv) if Manta Ray is in default under the performance standards set forth in the Agreement. The Agreement may be terminated or canceled by Manta Ray without cause at any time with at least 180 days notice if (i) we are in default in the performance of any payment obligations; (ii) we dissolve, liquidate or terminate our separate corporate existence; (iii) we make a general assignment for the benefit of creditors or admit in writing our inability to pay our debts generally as they become due; or (iv) we sell or lease our Pipeline to a third party. Other operating costs and expenses for the period from November 23, 2010 through December 31, 2010 include payments to Manta Ray totaling $0.6 million for operation and management services rendered to us.

F-59

We rent offshore platform space from an affiliate of Enterprise and a third party. Total rent paid to the affiliate of Enterprise was $69 thousand for the period from November 23, 2010 through December 31, 2010. See Note 5 for additional information regarding this operating lease.

5. Commitments and Contingencies

Operating Leases

Lease and rent expense included in operating income was $224 thousand for the period from November 23, 2010 to December 31, 2010.

We rent offshore platform space from an affiliate of Enterprise and a third party. Total rent paid for this platform space was $138 thousand for the period from November 23, 2010 through December 31, 2010. The agreement has an indefinite term and will continue until the platform is abandoned. However, we can terminate the agreement at any time if we cease operations on the platform. As a result, there are no future minimum payment obligations attributable to this agreement.

We lease right-of-way held in connection with our Pipeline. In general, our payments for right-of-way easements are determined by the underlying contracts, which typically include a stated fixed fee. Certain of our right-of-way leases contain rent escalation clauses whereby the rent is adjusted periodically for inflation. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. The following table presents our minimum payment obligations under operating leases for right-of-way:

2011	$	21
2012		21
2013		22
2014		22
2015		22
Thereafter		233
Total	$	341

Other Matters

We are subject to potential loss contingencies arising from the course of our regular business operations. These may result from federal, state and local environmental, health and safety laws and regulations and third-party litigations. There are no matters currently which, in the opinion of our management, will have a material adverse effect on the financial position or results of our operations.

6. Significant Risks

Nature of Operations

Offshore crude oil pipeline systems such as ours are affected by oil exploration and production activities. Crude oil reserves are depleting assets that will produce over a finite period. Our Pipeline must access additional reserves to offset either (i) the natural decline in production from existing connected wells or (ii) the loss of any production to a competitor. We actively seek to offset the loss of volumes due to depletion by adding connections to new customers and fields.

In April 2010, the Deepwater Horizon drilling rig caught fire and sank in the Gulf of Mexico, resulting in an oil spill that has significantly impacted ecological resources in the Gulf of Mexico. As a result, in May 2010, a federal offshore drilling moratorium went into effect which halted drilling of uncompleted and new oil and gas wells (in water deeper than 500 feet) in the Gulf of Mexico with certain limited exceptions and halted consideration of drilling permits for deepwater wells. The moratorium was lifted in October 2010; however, it is uncertain at this time how and to what extent oil and natural gas supplies from the Gulf of Mexico and other offshore drilling areas will be affected. A continued decline in oil and natural gas production volumes and or a failure to achieve anticipated future production due to limitations caused by the federal moratorium could have a material adverse effect on our financial position, results of operations or cash flows.

F-60

Weather-Related Risks

Our assets are located offshore Texas and Louisiana in the Gulf of Mexico, which is prone to tropical weather events such as hurricanes. Our Partners are required to maintain certain levels of insurance with respect to our assets. If our assets were materially damaged in a storm, it could have a material impact on our financial position and results of operations.

F-61

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