Edgar Filing: GENESIS ENERGY LP

form10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2010

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

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

919 Milam, Suite 2100, Houston, TX (Address of principal executive offices)	77002 (Zip code)

Registrant's telephone number, including area code:

(713) 860-2500

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

NONE

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

Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).

Yes o No o

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

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Smaller reporting company o

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

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Common Units outstanding as of May 3, 2010: 39,585,692

GENESIS ENERGY, L.P.

Form 10-Q

INDEX

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements	Page

	Unaudited Consolidated Balance Sheets – March 31, 2010 and December 31, 2009	3
	Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	4
	Unaudited Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009	5
	Unaudited Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2010 and 2009	6
	Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	7
	Notes to Unaudited Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	33

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults upon Senior Securities	33
Item 4.	[Removed and Reserved]	33
Item 5.	Other Information	33
Item 6.	Exhibits	33

SIGNATURES		34

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Index

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS

(In thousands)

	March 31, 2010			December 31, 2009

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,210		$	4,148
Accounts receivable - trade, net of allowance for doubtful accounts of $1,324 and $1,372 at March 31, 2010 and December 31, 2009, respectively		123,671			127,248
Accounts receivable - related party		622			2,617
Inventories		47,928			40,204
Investment in direct financing leases, net of unearned income - current portion		4,302			4,202
Other		14,099			10,825
Total current assets		201,832			189,244

FIXED ASSETS, at cost		373,932			373,927
Less: Accumulated depreciation		(94,166	)		(89,040	)
Net fixed assets		279,766			284,887

INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income		171,919			173,027
CO2 ASSETS, net of accumulated amortization		19,230			20,105
EQUITY INVESTEES AND OTHER INVESTMENTS		14,613			15,128
INTANGIBLE ASSETS, net of accumulated amortization		131,739			136,330
GOODWILL		325,046			325,046
OTHER ASSETS, net of accumulated amortization		3,831			4,360

TOTAL ASSETS	$	1,147,976		$	1,148,127

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	118,823		$	114,428
Accounts payable - related party		1,932			3,197
Accrued liabilities		21,482			23,803
Total current liabilities		142,237			141,428


LONG-TERM DEBT, $46,400 and $46,900 nonrecourse to Genesis Energy, L.P. at March 31, 2010 and December 31, 2009, respectively		378,400			366,900
DEFERRED TAX LIABILITIES		14,895			15,167
OTHER LONG-TERM LIABILITIES		5,611			5,699
COMMITMENTS AND CONTINGENCIES (Note 13)

PARTNERS' CAPITAL:

Common unitholders, 39,586 and 39,488 units issued and outstanding, at March 31, 2010 and December 31, 2009, respectively		574,137			585,554
General partner		10,955			11,152
Accumulated other comprehensive loss		(791	)		(829	)
Total Genesis Energy, L.P. partners' capital		584,301			595,877
Noncontrolling interests		22,532			23,056
Total partners' capital		606,833			618,933

TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,147,976		$	1,148,127

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

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2010			2009
REVENUES:
Supply and logistics:
Unrelated parties	$	419,702		$	187,818
Related parties		397			1,244
Refinery services		29,502			48,294
Pipeline transportation, including natural gas sales:
Transportation services - unrelated parties		7,009			3,401
Transportation services - related parties		5,734			8,294
Natural gas sales revenues		915			713
CO2 marketing:
Unrelated parties		2,736			3,052
Related parties		536			677
Total revenues		466,531			253,493

COSTS AND EXPENSES:
Supply and logistics costs:
Product costs - unrelated parties		392,191			163,731
Product costs - related parties		-			1,713
Operating costs		22,616			17,269
Refinery services operating costs		16,227			35,333
Pipeline transportation costs:
Pipeline transportation operating costs		3,564			2,494
Natural gas purchases		865			654
CO2 marketing costs:
Transportation costs		1,234			1,307
Other costs		16			16
General and administrative		6,294			8,754
Depreciation and amortization		13,406			15,419
Net loss (gain) on disposal of surplus assets		80			(218	)
Total costs and expenses		456,493			246,472
OPERATING INCOME		10,038			7,021

Equity in earnings of joint ventures		182			1,906
Interest income		14			21
Interest expense		(3,218	)		(3,056	)
Income before income taxes		7,016			5,892
Income tax expense		(691	)		(591	)
NET INCOME		6,325			5,301

Net loss (income) attributable to noncontrolling interests		560			(11	)

NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	6,885		$	5,290

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Index

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS

OF OPERATIONS - CONTINUED

(In thousands, except per unit amounts)

	Three Months Ended March 31,
	2010		2009

NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
PER COMMON UNIT:
BASIC	$	0.06	$	0.16
DILUTED	$	0.06	$	0.16

WEIGHTED AVERAGE OUTSTANDING
COMMON UNITS:
BASIC		39,548		39,457
DILUTED		39,596		39,566

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

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME

(In thousands)

	Three Months Ended March 31,
	2010			2009

Net income	$	6,325		$	5,301
Change in fair value of derivatives:
Current period reclassification to earnings		280			132
Changes in derivative financial instruments - interest rate swaps		(204	)		(128	)
Comprehensive income		6,401			5,305
Comprehensive loss (income) attributable to noncontrolling interests		522			(3	)
Comprehensive income attributable to Genesis Energy, L.P.	$	6,923		$	5,302

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

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Index

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(In thousands)

	Partners' Capital
	Number of Common Units		Common Unitholders			General Partner			Accumulated Other Comprehensive Loss			Non- Controlling Interests			Total Capital

Partners' capital, January 1, 2010		39,488	$	585,554		$	11,152		$	(829	)	$	23,056		$	618,933
Comprehensive income:
Net income		-		2,814			4,071			-			(560	)		6,325
Interest rate swap losses reclassified to interest expense		-		-			-			138			142			280
Interest rate swap loss		-		-			-			(100	)		(104	)		(204	)
Cash contributions		-		-			37			-			-			37
Cash distributions		-		(14,251	)		(2,328	)		-			(2	)		(16,581	)
Contribution for executive compensation (See Note 9)		-		-			(1,977	)		-			-			(1,977	)
Unit based compensation expense		98		20			-			-			-			20
Partners' capital, March 31, 2010		39,586	$	574,137		$	10,955		$	(791	)	$	22,532		$	606,833

	Partners' Capital
									Accumulated
	Number of								Other			Non-
	Common		Common			General			Comprehensive			Controlling			Total
	Units		Unitholders			Partner			Loss			Interests			Capital

Partners' capital, January 1, 2009		39,457	$	616,971		$	16,649		$	(962	)	$	24,804		$	657,462
Comprehensive income:
Net income		-		6,481			(1,191	)		-			11			5,301
Interest rate swap loss reclassified to interest expense		-		-			-			64			68			132
Interest rate swap loss		-		-			-			(63	)		(65	)		(128	)
Cash distributions		-		(13,021	)		(1,089	)		-			(1	)		(14,111	)
Contribution for executive compensation (See Note 9)		-		-			2,146			-			-			2,146
Unit based compensation expense		-		268			-			-			-			268
Partners' capital, March 31, 2009		39,457	$	610,699		$	16,515		$	(961	)	$	24,817		$	651,070

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

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GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6,325		$	5,301
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation of fixed assets		5,862			6,271
Amortization of intangible and CO2 assets		7,544			9,148
Amortization of credit facility issuance costs		455			480
Amortization of unearned income and initial direct costs on direct financing leases		(4,449	)		(4,555	)
Payments received under direct financing leases		5,464			5,462
Equity in earnings of investments in joint ventures		(182	)		(1,906	)
Distributions from joint ventures - return on investment		702			400
Non-cash effect of unit-based compensation plans		243			679
Non-cash compensation charge		(1,977	)		2,146
Deferred and other tax liabilities		186			459
Other non-cash items		1,277			(517	)
Net changes in components of operating assets and liabilities (See Note 10)		(8,160	)		(20,211	)
Net cash provided by operating activities		13,290			3,157

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		(2,299	)		(17,076	)
Investments in joint ventures and other investments		-			(21	)
Other, net		268			529
Net cash used in investing activities		(2,031	)		(16,568	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		130,400			77,600
Bank repayments		(118,900	)		(54,100	)
General partner contributions		37			-
Noncontrolling interests contributions, net of distributions		(2	)		(1	)
Distributions to common unitholders		(14,251	)		(13,021	)
Distributions to general partner interest		(2,328	)		(1,089	)
Other, net		847			429
Net cash (used in) provided by financing activities		(4,197	)		9,818

Net increase (decrease) in cash and cash equivalents		7,062			(3,593	)
Cash and cash equivalents at beginning of period		4,148			18,985

Cash and cash equivalents at end of period	$	11,210		$	15,392

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

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

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

Pipeline transportation of crude oil and carbon dioxide;

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);

Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products by trucks and barges; and

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

Our 2% general partner interest is held by Genesis Energy, LLC, a Delaware limited liability company. Our general partner manages our operations and activities and employs our officers and personnel, who devote 100% of their efforts to our management.

Basis of Presentation and Consolidation

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The consolidated financial statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009.

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.

2. Consolidated Joint Venture – DG Marine

DG Marine Transportation, LLC (DG Marine) is a joint venture we formed with TD Marine (a related party). TD Marine owns (indirectly) a 51% economic interest in DG Marine, and we own (directly and indirectly) a 49% economic interest. This joint venture gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.

We have determined that DG Marine is a variable interest entity (“VIE”) as certain of our voting rights are not proportional to our 49% economic interest. Accounting provisions require the primary beneficiary to consolidate VIEs. 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 are considered to be the primary beneficiary due to (i) our involvement in the design of DG Marine, (ii) the ongoing involvement with regards to financial and operating decision making of DG Marine, excluding matters related to new contracts and vessel disposal which are decided solely by TD Marine, and (iii) the financial support we provide to DG Marine. TD Marine has no requirements to make any additional contributions to DG Marine.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

We have entered into a subordinated loan agreement with DG Marine whereby we may (at our sole discretion) lend up to $25 million to DG Marine. The loan agreement provides for DG Marine to pay us interest on any loans at the prime rate plus 4%. Those loans will mature on January 31, 2012. Under that subordinated loan agreement, DG Marine is required to make monthly payments to us of principal and interest to the extent DG Marine has any available cash that otherwise would have been distributed to the owners of DG Marine in respect of their equity interest. DG Marine also has a revolving credit facility with a syndicate of financial institutions that includes restrictions on DG Marine’s ability to make principal and interest payments under our subordinated loan agreement and distributions in respect of our equity interest. At both March 31, 2010 and December 31, 2009, $25 million was outstanding under the subordinated loan agreement; however this amount was eliminated in consolidation. Due to the credit facility restrictions, no interest payments were made by DG Marine to us during the three months ended March 31, 2010. The proceeds of the loan were used to reduce the amount outstanding under the DG Marine credit facility. Additionally, at March 31, 2010 and December 31, 2009, Genesis had provided a $7.5 million guaranty to the lenders under the DG Marine credit facility.

At March 31, 2010 and December 31, 2009, our consolidated balance sheets included the following amounts related to DG Marine:

	March 31, 2010			December 31, 2009
Cash	$	809		$	585
Accounts receivable - trade		4,177			3,216
Other current assets		1,574			2,421
Fixed assets, at cost		124,316			124,276
Accumulated depreciation		(10,786	)		(9,139	)
Intangible assets, net		1,663			1,758
Other assets		984			1,174
Total assets	$	122,737		$	124,291

Accounts payable	$	2,027		$	1,788
Accrued liabilities		2,520			3,601
Long-term debt		46,400			46,900
Other long-term liabilities		522			683
Total liabilities	$	51,469		$	52,972

3. Inventories

Inventories are valued at the lower of cost or market. The costs of inventories did not exceed market values at March 31, 2010 and December 31, 2009. The major components of inventories were as follows:

	March 31, 2010		December 31, 2009
Crude oil		6,331		13,901
Petroleum products		35,689		22,150
Caustic soda		2,664		1,985
NaHS		3,242		2,154
Other		2		14
Total inventories	$	47,928	$	40,204

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

4. Intangible Assets and Goodwill

Intangible Assets

The following table reflects the components of intangible assets being amortized at the dates indicated:

			March 31, 2010						December 31, 2009
	Weighted Amortization Period in Years		Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value

Customer relationships:
Refinery services		5	$	94,654	$	44,372	$	50,282	$	94,654	$	41,450	$	53,204
Supply and logistics		5		35,430		16,615		18,815		35,430		15,493		19,937
Supplier relationships -
Refinery services		2		36,469		29,282		7,187		36,469		28,551		7,918
Licensing Agreements -
Refinery services		6		38,678		12,707		25,971		38,678		11,681		26,997
Trade names -
Supply and logistics		7		18,888		5,966		12,922		18,888		5,444		13,444
Favorable lease -
Supply and logistics		15		13,260		1,263		11,997		13,260		1,144		12,116
Other		5		5,901		1,336		4,565		3,823		1,109		2,714
Total		5	$	243,280	$	111,541	$	131,739	$	241,202	$	104,872	$	136,330

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

Year Ended December 31	Amortization Expense to be Recorded
Remainder of 2010	$	19,952
2011	$	21,918
2012	$	18,261
2013	$	14,264
2014	$	11,790
2015	$	9,856

Goodwill

The carrying amount of goodwill by business segment at both March 31, 2010 and December 31, 2009 was $301.9 million to refinery services and $23.1 million to supply and logistics.

5. Debt

Our obligations under credit facilities consisted of the following:

	March 31, 2010		December 31, 2009

Genesis Credit Facility, variable rate, due November 2011	$	332,000	$	320,000
DG Marine Credit Facility, variable rate, due July 2011		46,400		46,900
Total Long-Term Debt	$	378,400	$	366,900

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2010, our borrowing base was $387 million, and we had $332 million borrowed and $5 million in letters of credit outstanding. Thus, our total remaining availability at March 31, 2010 was approximately $50 million under our credit facility. Our borrowing base may be increased up to $500 million for material acquisitions and internal growth projects, subject to lender approval.

The DG Marine revolving credit facility is non-recourse to us and TD Marine (other than with respect to our investment in DG Marine). Although DG Marine’s debt is non-recourse to us, our ownership interest in DG Marine is pledged to secure its indebtedness.

We believe that the fair value of the debt outstanding under our revolving credit facilities is lower than its carrying value as of March 31, 2010 since the terms of the facilities are more favorable than the terms that might be expected to be available in the current credit environment. We are unable to estimate the fair value of this bank debt due to the potential variability of expected outstanding balances under the facilities.

6. Distributions and Net Income Per Common Unit

Distributions

We paid or will pay the following distributions in 2009 and 2010:

	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 (1)	$	0.3675	$	14,548	$	297	$	2,339	$	17,184

(1) This distribution will be paid on May 14, 2010 to our general partner and unitholders of record as of May 4, 2010.

Net Income Allocation to Partners

Net income is allocated to our partners in the Unaudited Consolidated Statements of Partners’ Capital as follows:

To our general partner – income in the amount of the incentive distributions paid in the period.

To our general partner – expense in the amount of the executive compensation expense to be borne by our general partner (See Note 9).

To our limited partners and general partner – the remainder of net income in the ratio of 98% to the limited partners and 2% to our general partner.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Net Income Per Common Unit

	Three Months Ended March 31,
	2010			2009
Numerators for basic and diluted net income
per common unit:
Income attributable to Genesis Energy, L.P.	$	6,885		$	5,290
Less: General partner's incentive distribution to be paid for the period		(2,339	)		(1,125	)
Add: (Credit) Expense for Class B and Series B Awards (Note 9)		(1,977	)		2,146
Subtotal		2,569			6,311
Less: General partner 2% ownership		(51	)		(126	)
Income available for common unitholders	$	2,518		$	6,185

Denominator for basic per common unit:
Common Units		39,548			39,457

Denominator for diluted per common unit:
Common Units		39,548			39,457
Phantom Units		48			109
		39,596			39,566

Basic net income per common unit	$	0.06		$	0.16
Diluted net income per common unit	$	0.06		$	0.16

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

7. Business Segment Information

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures. Our segment margin definition also excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and maintenance capital investment.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

	Pipeline Transportation		Refinery Services			Supply & Logistics			Industrial Gases		Total
Three Months Ended March 31, 2010
Segment margin (a)	$	10,399	$	13,260		$	4,512		$	2,494	$	30,665

Maintenance capital expenditures	$	56	$	459		$	110		$	-	$	625

Revenues:
External customers	$	11,412	$	31,370		$	420,477		$	3,272	$	466,531
Intersegment (b)		2,246		(1,868	)		(378	)		-		-
Total revenues of reportable segments	$	13,658	$	29,502		$	420,099		$	3,272	$	466,531

Three Months Ended March 31, 2009
Segment margin (a)	$	10,225	$	12,759		$	5,956		$	3,023	$	31,963

Maintenance capital expenditures	$	274	$	493		$	181		$	-	$	948

Revenues:
External customers	$	11,315	$	49,905		$	188,544		$	3,729	$	253,493
Intersegment (b)		1,093		(1,611	)		518			-		-
Total revenues of reportable segments	$	12,408	$	48,294		$	189,062		$	3,729	$	253,493

A reconciliation of Segment Margin to income before income taxes for the periods presented is as follows:

	Three Months Ended March 31,
	2010			2009

Segment Margin	$	30,665		$	31,963
Corporate general and administrative expenses		(5,430	)		(7,501	)
Depreciation and amortization		(13,406	)		(15,419	)
Net (loss) gain on disposal of surplus assets		(80	)		218
Interest expense, net		(3,204	)		(3,035	)
Non-cash credits not included in segment margin		(224	)		(716	)
Other non-cash items affecting segment margin		(1,305	)		382
Income before income taxes	$	7,016		$	5,892

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

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

8. Transactions with Related Parties

Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. Affiliates of Denbury Resources, Inc. sold its interests in our general partner on February 5, 2010. Transactions with Denbury are included in the table below as related party transactions through February 5, 2010.

The transactions with related parties were as follows:

	Three Months Ended March 31,
	2010		2009

Operations, general and administrative services provided by our general partner	$	11,305	$	16,380
Sales of CO2 to Sandhill	$	536	$	677
Petroleum products sales to Davison family businesses	$	215	$	196
Truck transportation services provided to Denbury	$	182	$	1,048
Pipeline transportation services provided to Denbury	$	1,364	$	3,714
Payments received under direct financing leases from Denbury	$	5,464	$	5,462
Pipeline transportation income portion of direct financing lease fees	$	1,502	$	4,606
Pipeline monitoring services provided to Denbury	$	10	$	30
Directors' fees paid to Denbury	$	-	$	51
CO2 transportation services provided by Denbury	$	373	$	1,240
Crude oil purchases from Denbury	$	-	$	1,713

Amounts due to and from Related Parties

At March 31, 2010 and December 31, 2009, we owed our general partner $1.9 million and $2.1 million for administrative services, respectively. Sandhill owed us $0.5 million and $0.7 million for purchases of CO2 at March 31, 2010 and December 31, 2009, respectively. Denbury owed us $1.9 million for truck and pipeline transportation services and we owed Denbury $1.0 million for CO2 transportation charges at December 31, 2009.

9. Equity-Based Compensation

We recorded charges and credits related to our equity-based compensation plans and awards for the three months ended March 31, 2010 and 2009 as follows:

Expense (Credits) Related to Equity-Based Compensation

	Three Months Ended
	March 31,
Statement of Operations	2010			2009
Pipeline operating costs	$	87		$	33
Refinery services operating costs		178			77
Supply and logistics operating costs		368			209
General and administrative expenses		(1,328	)		2,510
Total	$	(695	)	$	2,829

In connection with the sale of our general partner on February 5, 2010, our general partner redeemed all of its Class B Member Interests and replaced its Class A Member Interest with Series A units and Series B units.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Series B Units

Our general partner uses the Series B Units, which have no voting rights, as part of its long-term compensation structure for our management team. A total of 1,000 Series B Units may be issued by our general partner. 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. The Series B Units will be converted into Series A Units on the seventh anniversary of the issuance date of the awards (unless a conversion occurs at a prior date due to a public offering or a change in control of our general partner) as long as the award recipients remain in service.

Subject to the rights of the holders of the Series A units in our general partner to receive distributions up to certain threshold amounts, holders of Series B units, upon vesting, have the right to receive a share of the distributions paid by us to our general partner. With regard to the right to receive a share of distributions, the Series B Units vest 25% per year on each of the next four anniversary dates of the award. The four-year vesting requirement would also be applicable to any conversion due to a public offering should that conversion occur in the first four years after issuance of the award.

Although the Series B units represent an equity interest in our general partner and our general partner will not seek reimbursement under our partnership agreement for the value of these compensation arrangements, we will record non-cash expense for the estimated fair value of the awards. The estimated fair value of the converted Series B units will be recomputed at each quarterly reporting date until conversion, and the expense to be recorded will be adjusted based on that fair value, with an offsetting entry to the capital account of our general partner.

Management’s estimates of the fair value of these awards are based on a number of future events, including estimates of the distributions that would be received by our general partner in the future through the conversion date of February 5, 2017, the fair value of our general partner at February 5, 2017, and assumptions about an appropriate discount rate. Changes in our assumptions will change the amount of expense we record.

At March 31, 2010, management estimates that the fair value of the Series B Units granted to our management team is approximately $8.4 million. This estimate of the fair value was determined using a discount rate of 20%, representing the risks inherent in the assumptions we used and the time value until final conversion of the Series B Units. Due to the limited number of holders of Series B Units, we assumed a forfeiture rate of zero. For the three months ended March 31, 2010, we recorded non-cash expense of $0.2 million for these awards.

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.

Class B Membership Interests

All of the Class B membership interests in our general partner held by the existing management team were either (i) converted into Series A units in our general partner or (ii) redeemed by our general partner on February 5, 2010. The amounts owed under the deferred compensation plan with the management team was similarly converted or redeemed. 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 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. The difference between the recorded cumulative compensation expense related to these interests through December 31, 2009 of $17.5 million and the total compensation expense of $15.4 million was recorded as a reduction of expense in the first quarter of 2010.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2010 Long Term Incentive Plan

In the second quarter of 2010, our general partner 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 directors of our general partner, and employees and other representatives of our general partner and its affiliates 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 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 “GCBD Committee”) of the board of directors of our general partner.

The GCBD 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. The GCBD Committee made the initial awards under the 2010 Plan in April 2010.

10. Supplemental Cash Flow Information

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

	Three Months Ended March 31,
	2010			2009
Decrease (increase) in:
Accounts receivable	$	5,521		$	3,971
Inventories		(9,502	)		(2,851	)
Other current assets		(2,609	)		(2,373	)
Increase (decrease) in:
Accounts payable		1,462			(10,099	)
Accrued liabilities		(3,032	)		(8,859	)
Net changes in components of operating assets and liabilities, net of working capital acquired	$	(8,160	)	$	(20,211	)

Cash received by us for interest for the three months ended March 31, 2010 and 2009 was $4,900 and $3,000, respectively. Payments of interest and commitment fees were $2.7 million and $3.9 million for the three months ended March 31, 2010 and 2009, respectively.

Cash received for income tax refunds during the three months ended March 31, 2010 was $0.1 million. Cash paid for income taxes during the three months ended March 31, 2009 was $0.9 million.

At March 31, 2010, we had incurred liabilities for fixed asset and other asset additions totaling $1.3 million that had not been paid at the end of the first quarter, and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” and “Other, net” under investing activities on the Unaudited Consolidated Statements of Cash Flows. At March 31, 2009, we had incurred $0.6 million of such liabilities that had not been paid at that date and are not included in “Payments to acquire fixed and intangible assets” under investing activities.

11. Derivatives

Commodity Derivatives

At March 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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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

	Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		37		-
Weighted average contract price per bbl	$	82.19	$	-

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		481		85
Weighted average contract price per bbl	$	81.56	$	80.58

Heating oil futures:
Contract volumes (1,000 bbls)		34		-
Weighted average contract price per gal	$	2.08	$	-

RBOB gasoline futures:
Contract volumes (1,000 bbls)		13		-
Weighted average contract price per gal	$	2.21	$	-

Crude oil written calls:
Contract volumes (1,000 bbls)		40		-
Weighted average premium received	$	2.33	$	-

Interest Rate Derivatives

DG Marine utilizes swap contracts with financial institutions to hedge interest payments for $32.9 million of its outstanding debt through July 2011. The weighted average interest rate of these swap contracts is 4.45%. DG Marine expects these interest rate swap contracts to be highly effective in limiting its exposure to fluctuations in market interest rates; therefore, we have designated these swap contracts as cash flow hedges under accounting guidance. The effective portion of the derivative represents the change in fair value of the hedge that offsets 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 is reported as a component of Accumulated Other Comprehensive Income (Loss) (AOCI) and reclassified into future earnings contemporaneously as interest expense associated with the underlying debt under the DG Marine credit facility is recorded. To the extent that the change in the fair value of the interest rate swaps does not perfectly offset the change in the fair value of our exposure to interest rates, the ineffective portion of the hedge will be immediately recognized in interest expense in our Unaudited Consolidated Statements of Operations.

Financial Statement Impacts

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

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Derivative Assets and Liabilities

	Asset Derivatives
	Unaudited
	Consolidated
	Balance Sheets	Fair Value
	Location	March 31, 2010		December 31, 2009
Commodity derivatives - futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other Current Assets	$	95	$	53
Undesignated hedges	Other Current Assets		176		307
Total asset derivatives		$	271	$	360

	Liability Derivatives
	Unaudited
	Consolidated
	Balance Sheets	Fair Value
	Location	March 31, 2010			December 31, 2009

Commodity derivatives - futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other Current Assets	$	(166	)(1)	$	(159	)(1)
Undesignated hedges	Other Current Assets		(1,357	)(1)		(2,118	)(1)
Total commodity derivatives			(1,523	)		(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		(1,266	)		(1,176	)
Portion expected to be reclassified into earnings after one year	Other Long-term Liabilities		(346	)		(512	)

Total liability derivatives		$	(3,135	)	$	(3,965	)

(1)

These derivative liabilities have been funded with margin deposits recorded in our Unaudited Consolidated Balance Sheets in Other Current Assets.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

	Effect on Unaudited Consolidated Statements of Operations and Other Comprehensive Income (Loss)
	Amount of Gain (Loss) Recognized in Income
	Supply & Logistics						Interest Expense						Income (Loss)
	Product Costs						Reclassified from AOCI						Effective Portion
	Three Months						Three Months						Three Months
	Ended March 31,						Ended March 31,						Ended March 31,
	2010			2009			2010			2009			2010			2009
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	$	274	(1)	$	(529	)(1)	$	-		$	-		$	-		$	-
Contracts not considered hedges under accounting guidance		(552	)		182			-			-			-			-
Total commodity derivatives		(278	)		(347	)		-			-			-			-

Interest rate swaps designated as cash flow hedges under accounting guidance		-			-			(280	)		(132	)		(204	)		(128	)

Total derivatives	$	(278	)	$	(347	)	$	(280	)	$	(132	)	$	(204	)	$	(128	)

(1) Represents the amount of 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 $0.1 million and $1.0 million for March 31, 2010 and March 31, 2009, respectively.

During the first three months of 2010 and 2009, DG Marine’s interest rate hedges fully offset the hedged risk; therefore, there was no ineffectiveness recorded for the hedges.

We expect to reclassify $1.3 million in unrealized losses from AOCI into interest expense during the next 12 months. Because a portion of these losses are based on market prices at the current period end, actual amounts to be reclassified to earnings will differ and could vary materially as a result of changes in market conditions. We have no derivative contracts with credit contingent features.

12. 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 March 31, 2010. 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 March 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	$	271		$	-	$	-		$	360		$	-	$	-
Liabilities	$	(1,523	)	$	-	$	-		$	(2,277	)	$	-	$	-

Interest rate swaps - Liabilities	$	-		$	-	$	(1,612	)	$	-		$	-	$	(1,688	)

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2010, we had no Level 2 fair value measurements.

Level 3

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

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

	Three Months Ended March 31,
	2010			2009
Balance at beginning of period		(1,688	)		(1,964	)
Realized and unrealized gains (losses)-
Reclassified into interest expense for settled contracts		280			132
Included in other comprehensive income		(204	)		(128	)
Balance at end of period	$	(1,612	)	$	(1,960	)


Total amount of losses for the three months ended included in earnings attributable to the change in unrealized losses relating to liabilities still held at March 31, 2010 and 2009, respectively	$	(21	)	$	(11	)

See Note 11 for additional information on our derivative instruments.

We generally apply fair value techniques on a non-recurring basis associated with (1) valuing potential impairment loss related to goodwill, (2) valuing asset retirement obligations, and (3) valuing potential impairment loss related to long-lived assets.

13. Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any material 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.

We are subject to lawsuits in the normal course of business, as well as examinations 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.

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Index

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

Included in Management’s Discussion and Analysis are the following sections:

Overview

Available Cash before Reserves

Results of Operations

Liquidity and Capital Resources

Commitments and Off-Balance Sheet Arrangements

New Accounting Pronouncements

In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are Segment Margin and Available Cash before Reserves. We define segment margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures. In addition, our segment margin definition excludes the non-cash effects of our equity-based compensation plans, and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant, and maintenance capital investment. A reconciliation of Segment Margin to income before income taxes is included in our segment disclosures in Note 7 to our unaudited consolidated financial statements.

Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation), the substitution of cash generated by our joint ventures in lieu of our equity income attributable to such joint ventures, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows. For additional information on Available Cash before Reserves and a reconciliation of this measure to cash flows from operations, see “Liquidity and Capital Resources - Non-GAAP Reconciliation” below.

Overview

In the first quarter of 2010, we reported net income attributable to the partnership of $6.9 million, or $0.06 per common unit. We generated $18.1 million of Available Cash before Reserves, and we will distribute $17.2 million to holders of our common units and general partner for the first quarter. During the first quarter of 2010, cash provided by operating activities was $13.3 million.

Reported Segment Margin impacting Available Cash was negatively impacted by a total of $3.1 million due to the impact of one time charges of $0.8 million associated with a significant pipeline integrity test on the Texas System, a net increase of $1.7 million of unrealized profit in inventory (offset by the unrealized loss on hedged value) and $0.6 million primarily associated with the significant narrowing of quality differentials and contango pricing conditions during the first quarter. These items coupled with $2.3 million of cash costs related to the change in our general partner reduced Available Cash before Reserves to $18.1 million for the first quarter of 2010, as opposed to $23.5 million before such items, as compared to $21.3 million in the prior year. The primary components impacting Available Cash before Reserves (a non GAAP measure) are Segment Margin, corporate general and administrative expenses (excluding non-cash charges) and maintenance capital expenditures.

On April 14, 2010, we increased our quarterly distribution rate to our common unitholders for the nineteenth consecutive quarter. In May of 2010, we will pay a distribution of $0.3675 per unit attributable to our first quarter of 2010, which represents an approximate 8.9% increase from our distribution of $0.3375 per unit for the first quarter of 2009. During the first quarter of 2010, we paid a distribution of $0.36 per unit related to the fourth quarter of 2009.

The current economic recession continues to restrict availability of credit and access to capital in our business environment. While we anticipate that the challenging economic environment may continue for some period of time, we believe our current cash balances, internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital needs. The financial performance of our existing businesses and the absence of any need to access the capital markets (other than opportunistically) may allow us to take advantage of acquisition and/or growth opportunities that may develop.

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Our ability to fund large new projects or make large acquisitions in the near term may be limited by the current conditions in the credit and equity markets due to limitations in our ability to consummate future debt or equity financings. We will consider other arrangements to fund large growth projects and acquisitions such as private equity and joint venture arrangements.

Available Cash before Reserves

Available Cash before Reserves was as follows (in thousands):

	Three Months Ended
	March 31, 2010
Net income attributable to Genesis Energy, L.P.	$	6,885
Depreciation and amortization		13,406
Cash received from direct financing leases not included in income		1,015
Cash effects of sales of certain assets		304
Effects of available cash generated by equity method investees not included in income		291
Cash effects of equity-based compensation plans		(551	)
Non-cash tax expense		186
Earnings of DG Marine in excess of distributable cash		(1,053	)
Non-cash equity-based compensation benefit		(695	)
Other non-cash items, net		(1,072	)
Maintenance capital expenditures		(625	)
Available Cash before Reserves	$	18,091

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the most comparable GAAP measure) for the three months ended March 31, 2010 in “Liquidity and Capital Resources – Non-GAAP Reconciliation” below. For the three months ended March 31, 2010, cash flows provided by operating activities were $13.3 million.

Results of Operations

Revenues, Costs and Expenses and Net Income

Our revenues for the three months ended March 31, 2010 increased $213 million, or 84% from the first quarter of 2009. Additionally, our costs and expenses increased $210 million, or 85% between the two periods. The majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs between the two first quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products. In the first quarter of 2010, closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $78.71 per barrel, as compared to $43.08 per barrel in the first quarter of 2009 – an increase of 83%. Net income (attributable to us) increased $1.6 million, or 30%, between the first quarter of 2009 and the same period in 2010. Contributing to that increase in net income was a net reduction in our non-cash general and administrative expenses for 2010 resulting from the sale of our general partner, which reduction was comprised of a decrease in the amount of our non-cash executive compensation and equity-based compensation resulting from our general partner’s redemption of certain equity interests, partially offset by other transaction related costs. For a more detailed discussion of these charges, refer to the section entitled Other Costs and Interest below.

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Index

Segment Margin

The contribution of each of our segments to total Segment Margin in the three months ended March 31, 2010 and 2009 was as follows:

	Three Months Ended March 31,
	2010		2009
	(in thousands)
Pipeline transportation	$	10,399	$	10,225
Refinery services		13,260		12,759
Supply and logistics		4,512		5,956
Industrial gases		2,494		3,023
Total Segment Margin	$	30,665	$	31,963

Pipeline Transportation Segment

Operating results for our pipeline transportation segment were as follows:

	Three Months Ended March 31,
Pipeline System	2010		2009

Mississippi-Bbls/day		23,626		25,364
Jay - Bbls/day		14,098		9,433
Texas - Bbls/day		19,355		29,827
Free State - Mcf/day		175,251		171,293

	Three Months Ended March 31,
	2010			2009
	(in thousands)


Crude oil tariffs and revenues from direct financing leases of crude oil pipelines	$	4,516		$	3,954
CO2 tariffs and revenues from direct financing leases of CO2 pipelines		6,688			6,744
Sales of crude oil pipeline loss allowance volumes		1,339			799
Non-income payments under direct financing leases		1,015			907
Other miscellaneous revenues		176			178
Revenues from natural gas tariffs and sales		939			733
Natural gas purchases		(865	)		(654	)
Pipeline operating costs, excluding non-cash charges for our equity-based compensation plans and other non-cash charges		(3,409	)		(2,436	)
Segment margin	$	10,399		$	10,225

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

Pipeline Segment Margin for the first quarter of 2010 increased $0.2 million. The significant components of this change were as follows:

Crude oil tariffs and revenues from direct financing leases increased $0.6 million. Volumes transported on our crude oil pipelines decreased 7,545 barrels per day; however the majority of the decline was attributable to volume decreases on the Texas System where the impact of volume decreases has a relatively low impact on revenues. Approximately 77% of the volume on that system in the first quarter was shipped on a tariff of $0.31 per barrel. The decreased volumes were principally due to downtime during pipeline integrity testing. The downtime on the Texas System decreased revenues by $0.2 million in the first quarter of 2010. The decrease in revenue from the Texas System was offset by increased revenue from the Jay System. Volumes on the Jay System increased as a producer connected to our Jay System restarted production from wells that were shut in during 2009 due to the decline in crude oil prices. Volume fluctuations on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, are primarily a result of Denbury’s crude oil production activities.

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Index

Tariff rate increases of approximately 7.6% on our Jay and Mississippi pipelines went into effect July 1, 2009, partially mitigating the effects of lower crude oil pipeline volumes. The rate increases increased Segment Margin between the two periods by approximately $0.3 million.

An increase in revenues from sales of pipeline loss allowance volumes increased segment margin by $0.5 million. Higher market prices for crude oil increased the value of our pipeline loss allowance volumes and, accordingly, our loss allowance revenues. Average crude oil market prices increased approximately $35 per barrel, or approximately 83%, between the two quarterly periods. The price increase more than offset the decrease in pipeline loss allowance volumes of approximately 3,400 barrels.

Pipeline integrity testing and other repairs increased by $0.8 million. Pipeline integrity tests on a segment of our Texas System in the first quarter of 2010 cost approximately $0.6 million. In addition, the costs of the tests on this segment of pipeline were higher than typical due to additional testing to increase the operating pressure of the segment. This segment of pipeline will not be required to be tested again until 2015. An additional $0.2 million of repair costs were incurred for various maintenance projects throughout our pipeline systems

Refinery Services Segment

Operating results for our refinery services segment were as follows:

	Three Months Ended March 31,
	2010			2009
Volumes sold:
NaHS volumes (Dry short tons "DST")		33,107			26,229
NaOH volumes (DST)		21,367			16,900
Total		54,474			43,129

NaHS revenues	$	24,254		$	31,253
NaOH revenues		4,802			15,548
Other revenues		2,314			3,104
Total external segment revenues	$	31,370		$	49,905

Segment margin	$	13,260		$	12,759

Average index price for NaOH per DST (1)	$	268		$	830

Raw material and processing costs as % of segment revenues		29	%		58	%
Delivery costs as a % of segment revenues		18	%		9	%

(1)

Source: Harriman Chemsult Ltd.

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Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

Refinery services Segment Margin for the first quarter of 2010 was $13.3 million, an increase of $0.5 million, or 4%, from the comparative period in 2009. The significant components of this fluctuation were as follows:

An increase in NaHS sales volumes of 26%. Macroeconomic conditions in some of our markets have improved, increasing the demand for NaHS. In particular, we have experienced a noticeable increase in NaHS demand from some copper and molybdenum miners and, to a lesser extent, from some industrial customers (primarily paper and pulp manufactures and leather tanners).

An increase in NaOH sales volumes of 26%. NaOH (or caustic soda) is a key component in the provision of our services for which we receive the by-product NaHS. We are a very large consumer of caustic soda, and our economies of scale and logistics capabilities allow us to effectively market caustic soda to third parties. Most of these third parties use the caustic soda in energy-related processes within their facilities.

Index prices for caustic soda averaged approximately $830 per DST in the first quarter of 2009. Market prices of caustic soda have decreased to an average of approximately $270 per DST during the first quarter of 2010. That volatility affects the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, changes in caustic soda prices generally do not materially affect Segment Margin attributable to our sulfur processing services because we generally pass those costs through to our NaHS sales customers.

Aggressive management of production costs. Raw material and processing costs related to our sulfur removal services and caustic soda sales activities as a percentage of our segment revenues declined 29% between the periods. Caustic soda is the key component of those raw material and processing costs. In addition, as discussed above, we also market caustic soda. As the market price of caustic soda has fluctuated in 2009 and 2010, we have minimized our acquisition costs by better timing of our purchases and by lowering the costs of transporting caustic soda to our refinery services locations through the use of our logistics resources. We have also taken steps to reduce processing costs.

Higher delivery logistics costs. Our costs of delivering NaHS and caustic soda to our customers increased as a percentage of segment revenues by 9% between the two quarterly periods. Although our logistics costs per unit increased only modestly, our logistics costs expressed as a percentage of revenues increased by 9% (to 18%) primarily because our sales price per unit, along with our cost per unit, dropped precipitously. Quantities delivered to customers also increased. Freight demand and fuel prices increased modestly in the 2010 period as economic conditions improved, increasing demand for transportation services and the increase in crude oil prices increased the cost of fuel used in transporting these products.

Supply and Logistics Segment

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

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	Three Months Ended March 31,
	2010			2009
	(in thousands)
Supply and logistics revenue	$	420,099		$	189,062
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions		(392,191	)		(165,317	)
Operating and segment general and administrative costs, excluding non-cash charges for stock-based compensation and other non-cash expenses		(23,396	)		(17,789	)
Segment margin	$	4,512		$	5,956

Volumes of crude oil and petroleum products - average barrels per day		54,869			41,489

Three Months Ended March 31, 2010 as Compared to Three Months Ended March 31, 2009

The average market prices of crude oil and petroleum products increased by more than $35 per barrel, or approximately 83%, between the two quarterly periods; however that price volatility had a limited impact on our Segment Margin. More significant factors for us are discussed below.

The key factors affecting the two quarters were as follows:

The narrowing of quality differentials and contango pricing beginning late in the fourth quarter of 2009 and extending through the first quarter of 2010;

Increased opportunities to handle the heavy end petroleum products due to increased access to transportation services (including those of DG Marine) and storage facilities; and

Lower average charter rates at DG Marine’s inland marine barge operations.

Additionally, during the first quarter of 2010, the unrealized profit in inventory (offset by the unrealized loss on hedged value) increased by $1.7 million.

Beginning late in 2008 and throughout most of 2009, the crude oil market was in wide contango. When crude oil markets are in contango, oil prices for future deliveries are higher than for current deliveries, providing an opportunity for us to purchase crude oil at current market prices, re-sell it through futures contracts at future prices, and store it as inventory until delivery. In the first quarter of 2009, we took advantage of contango conditions, placing approximately 188,000 barrels of crude oil in storage throughout the quarter. In 2010, contango market conditions had narrowed such that crude oil sales prices were not sufficient to support the costs associated with storing inventory. Additionally, fluctuations in differentials between different grades of crude oil reduced margins on our gathering activities. As a result, margins from crude oil gathering and marketing activities declined approximately $2.0 million

Our petroleum products activities involve handling volumes from the heavy end of the refined barrel. Despite decreased refinery activity in the 2010 period due to economic conditions, our increased access to heavy products storage capacity leased from third parties and to barge transportation services through DG Marine resulted in an increase of approximately $1.4 million in the contribution of petroleum products activities to Segment Margin.

The inland marine transportation operations of DG Marine contributed $0.8 million less to Segment Margin in the first quarter of 2010 as compared to the first quarter of 2009. Declines in average charter rates for our tows (a tow is usually one pushboat and two barges) resulting from reduced refinery production in response to the economic conditions was the main contributor to the decline. Four additional barges that were under construction in the first quarter of 2009 were completed and placed in service in the second quarter of 2009.

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Industrial Gases Segment

Operating results from our industrial gases segment were as follows:

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Revenues from CO2 marketing	$	3,272		$	3,729
CO2 transportation and other costs		(1,250	)		(1,323	)
Available cash generated by equity investees		472			617
Segment margin	$	2,494		$	3,023

Volumes per day:
CO2 marketing - Mcf		61,490			69,833

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

Segment Margin from the industrial gases segment decreased between the quarterly periods primarily due to a decline in volumes delivered to our customers. Volumes declined 12% between the two quarterly periods as customers reduced purchases in response to economic conditions. The average sales price of CO2 was consistent between the quarters.

Our industrial gases segment experienced increased costs due to inflationary adjustments to the rates we are charged to transport CO2 to our customers. Average transportation rates increased by 9.0% over the average rates in the 2009 first quarter.

Other Costs, Interest, and Income Taxes

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

	Three Months Ended March 31,
	2010			2009
	(in thousands)

General and administrative expenses not separately identified below	$	5,229		$	5,389
Expenses related to change in owner of our general partner		1,762			-
Bonus plan expense		1,000			855
Equity-based compensation plans expense		280			364
Non-cash compensation expense related to management team		(1,977	)		2,146
Total general and administrative expenses	$	6,294		$	8,754

Comparing the three-month periods, the primary factor driving the decrease in general and administrative expenses related to the credit to expense recorded for the compensation arrangement between members of our management team and our general partner. On December 31, 2008, our general partner and members of our management team entered into an equity-based compensation arrangement whereby our management team could earn an interest in distributions attributable to our incentive distribution rights owned by our general partner. While the former owner of our general partner was responsible for the cash cost of this compensation with our management team, we recorded the expense of those arrangements with an offsetting non-cash capital contribution by our general partner. On February 5, 2010, as a result of the sale of our general partner, that equity-based compensation arrangement was settled. In the first quarter of 2010, we recorded a credit of $2.0 million to general and administrative expense related to the difference in the ultimate settlement value of $14.9 million and the amounts that were previously charged to expense related to this arrangement. In the first quarter of 2009, we recorded expense related to these non-cash compensation arrangements with our management team totaling $2.1 million, resulting in a $4.1 million reduction in expense between the periods. See Note 9 to our unaudited consolidated financial statements.

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Partially offsetting the reduction from those compensation arrangements were $1.8 million of expenses we incurred related to the sale of our general partner, including costs related to a public offering of the common units initially retained by the former owner of our general partner and severance arrangements for an executive officer. Additionally, affecting Available Cash before Reserves, but not net income, was an increase of approximately $0.6 million in exercises of stock appreciation rights.

Depreciation and amortization expense. Depreciation and amortization expense decreased by $2.0 million between the quarterly periods, primarily as a result of the lower amortization expense recognized on intangible assets. We amortize our intangible assets over the period during which we expect them to contribute to our future cash flows. The amortization we record on those assets is greater in the initial years following their acquisition because the value of our intangible assets such as customer relationships and trade names are generally more valuable in the first years after an acquisition. Accordingly, the amount of amortization we have recorded has declined since we acquired those assets in 2007.

Interest expense, net.

Interest expense, net was as follows:

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Interest expense, including commitment fees, excluding DG Marine	$	1,924		$	1,616
Amortization of facility fees, excluding DG Marine facility		163			163
Interest expense and commitment fees - DG Marine		1,131			1,363
Capitalized interest		-			(86	)
Interest income		(14	)		(21	)
Net interest expense	$	3,204		$	3,035

Although our average interest rate for borrowed funds was relatively flat quarter to quarter, our interest expense increased primarily because our average debt balance was $10.0 million higher in the first quarter of 2010 than the same period in 2009. DG Marine incurred interest expense of $1.1 million and $1.4 in the first quarter of 2010 and 2009, respectively, under its credit facility.

Income tax expense. Income tax expense relates to corporate-level income tax accruals (accrued by the Partnership) and Texas Margin Tax on our operations in Texas. As the majority of our operations are not conducted by corporations, income tax expense is not expected to be significant.

Liquidity and Capital Resources

Capital Resources/Sources of Cash

Recent market trends have indicated improvements in bank lending capacity and long-term interest rates from the situation in early 2009. We anticipate that our short-term working capital needs will be met through our current cash balances, future internally-generated funds and funds available under our credit facility. Existing capacity in our credit facility and $11.2 million of cash on hand, as well as the absence of any need to access the capital markets, may allow us to take advantage of attractive acquisition and/or growth opportunities that develop.

We continue to pursue a growth strategy that requires significant capital. We expect our short-term and long-term capital resources to include equity and debt offerings (public and private), revolving and term credit facilities and other financing transactions, in addition to cash generated from our operations. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs. In the near future, we also plan to restructure our credit facility – which we entered into in November 2006 and which expires in November 2011 – to reflect and better accommodate our larger and more diversified operations and resulting credit metrics. Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, to restructure and utilize our credit facility and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms. If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.

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We continue to monitor the credit markets and the economic outlook to determine the extent of the impact on our business environment. While we have experienced increases in demand for NaHS in 2010 resulting primarily from increased mining activities associated with increases in commodity prices for copper and molybdenum, we continue to experience lower demand for crude oil and petroleum products, primarily due to low utilization rates at refineries. We continue to adjust to the effects of these macroeconomic factors in our operating levels and financial decisions.

Our unaudited consolidated balance sheet at March 31, 2010 includes total long-term debt of $378.4 million, consisting of $46.4 million outstanding under the non-recourse DG Marine credit facility and $332 million outstanding under our credit facility. Outstanding letters of credit under our credit facility at March 31, 2010 were $5.0 million. Our borrowing base under our $500 million credit facility is a function of our EBITDA (earnings before interest, taxes, depreciation and amortization), as defined in our credit agreement for our most recent four calendar quarters.

Our credit facility has provisions that allow us to increase our borrowing base for material acquisitions. Upon the completion of four full quarters of operations including the acquired operations, the EBITDA multiple used to determine our borrowing base is reduced from 4.75 times to 4.25 times. At March 31, 2010, our borrowing base was calculated using our last four quarters of EBITDA with a 4.25 multiplier; therefore our borrowing base as of March 31, 2010 was $387 million. This borrowing base resulted in approximately $50 million of remaining credit as of March 31, 2010 in addition to $11.2 million of cash on hand and cash that we have temporarily invested in crude oil and petroleum products inventories. We believe that this level of credit will provide us sufficient liquidity to operate our business. We have committed capital available under our credit facility up to $500 million that we can access for material acquisitions that meet criteria specified in our credit agreement with the calculation of our borrowing base using the higher multiple and an agreed-upon amount of pro forma EBITDA associated with the acquisition, subject to lender approval.

Uses of Cash

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

Cash Flows from Operations. We utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

Debt and Other Financing Activities. Our sources of cash are primarily from operations and our credit facilities. Our net borrowings under our credit facility and the DG Marine credit facility totaled $11.5 million during the first quarter of 2010, of which $7.1 million increased cash on hand. The remainder of these borrowings related primarily to the investment in fixed assets and the payment of liabilities accrued at the 2009 year end for such items as annual bonus payments and property tax obligations. Additionally, we used funds to increase our petroleum products inventory levels to take advantage of blending and storage opportunities. We paid distributions totaling $16.6 million to our limited partners and our general partner during the first quarter of 2010. For a more detailed analysis of our recent distributions, see Note 6 to our unaudited consolidated financial statements.

Investing. We utilized cash flows for capital expenditures. The most significant investing activities in the first quarter of 2010 were expenditures related to our project to upgrade our information technology systems discussed below.

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Capital Expenditures, and Business and Asset Acquisitions

A summary of our expenditures for fixed assets and other asset acquisitions in the first quarter of 2010 and 2009 is as follows:

	Three Months Ended
	March 31,
	2010		2009
	(in thousands)
Capital expenditures for property, plant and equipment:
Maintenance capital expenditures:
Pipeline transportation assets		56		274
Supply and logistics assets		102		121
Refinery services assets		459		493
Administrative and other assets		8		60
Total maintenance capital expenditures		625		948

Growth capital expenditures:
Pipeline transportation assets		20		1,816
Supply and logistics assets		104		11,457
Refinery services assets		-		1,307
Information technology systems upgrade project		2,373		-
Total growth capital expenditures		2,497		14,580
Total		3,122		15,528

Capital expenditures attributable to unconsolidated affiliates		-		21
Total		-		21
Total capital expenditures	$	3,122	$	15,549

During the remainder of 2010, we expect to expend approximately $3.0 million for maintenance capital projects in progress or planned. We also plan to spend an additional $7 million to $8 million in capital costs to integrate and upgrade our information technology systems to be positioned for further growth. At March 31, 2010, contractual obligations related to the information technology systems totaled $4.8 million, which we will fund with borrowings under our credit facility.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in “Liquidity and Capital Resources – Capital Resources/Sources of Cash.” We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.

Non-GAAP Reconciliation

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

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

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Available Cash before Reserves is a liquidity measure used by our management to compare cash flows generated by us to the cash distribution paid to our limited partners and general partner. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2010 is as follows:

	Three Months Ended
	March 31, 2010
	(in thousands)
Cash flows from operating activities	$	13,290
Adjustments to reconcile operating cash flows to
Available Cash:
Maintenance capital expenditures		(625	)
Proceeds from sales of certain assets		224
Amortization of credit facility issuance fees		(455	)
Effects of available cash generated by equity method investees not included in cash flows from operating activities		(230	)
Earnings of DG Marine in excess of distributable cash		(1,053	)
Other items affecting available cash		(1,220	)
Net effect of changes in operating accounts not included in calculation of Available Cash		8,160
Available Cash before Reserves	$	18,091

Commitments and Off-Balance-Sheet Arrangements

Contractual Obligations and Commercial Commitments

There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2009.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2009, nor do we have any debt or equity triggers based upon our unit or commodity prices.

Forward Looking Statements

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

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demand for, the supply of, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids or “NGLs”, sodium hydrosulfide and caustic soda in the United States, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;

throughput levels and rates;

changes in, or challenges to, our tariff rates;

our ability to successfully identify and consummate strategic acquisitions, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;

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

changes in laws or regulations to which we are subject;

our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of existing debt agreements that contain restrictive financial covenants;

loss of key personnel;

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

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

the condition of the capital markets in the United States;

loss or bankruptcy of key customers;

the political and economic stability of the oil producing nations of the world; and

general economic conditions, including rates of inflation and interest rates.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our 2009 Annual Report on Form 10-K. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 11 to our Unaudited Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

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Item 4. Controls and Procedures

We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors.

For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to the risk factors since the filing of such Form 10-K.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. [Removed and Reserved]

Item 5. Other Information.

None.

Item 6. Exhibits

(a) Exhibits.

3.1		Certificate of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545)
3.2		Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15, 2005)
3.3		Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 2007)
3.4		Amendment No. 2 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 10.2 to Form 8-K dated March 5, 2010)
3.5		Certificate of Limited Partnership of Genesis Crude Oil, L.P. (“the Operating Partnership”) (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996)
3.6		Fourth Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated June 15, 2005)
3.7		Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009)
3.8		Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009)
3.8		Limited Liability Company Agreement of Genesis Energy, LLC dated December 29, 2008 (incorporated by reference to Exhibit 3.3 to Form 8-K dated January 7, 2009)
3.9		Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated February 5, 2010 (incorporated by reference to Exhibit 3.1 to Form 8-K dated February 11, 2010)
4.1		Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007)
10.1	*	2010 Long-Term Incentive Plan
10.2	*	Form of Directors Phantom Unit with DERs Agreement under 2010 Long-Term Incentive Plan
10.3	*	Form of Employee Phantom Unit with DERs Agreement under 2010 Long-Term Incentive Plan
10.4		Form of Indemnity Agreement, among Genesis Energy, LLC and Quintana Energy Partners II, L.P. and each of the Directors of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K dated March 5, 2010)
31.1	*	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2	*	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32	*	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934

*Filed herewith

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SIGNATURES

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

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

Date: May 10, 2010	By:	/s/ Robert V. Deere
		Robert V. Deere Chief Financial Officer