GENESIS ENERGY LP - Quarter Report: 2011 June (Form 10-Q)

GENESIS ENERGY LP - Quarter Report: 2011 June (Form 10-Q)

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Form 10-Q

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 June 30, 2011

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

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)


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

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

Registrant's telephone number, including area code: (713) 860-2500

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant 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 x No ¨

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act). Yes ¨ No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Class A Common Units outstanding as of August 2, 2011: 71,925,065

GENESIS ENERGY, L.P.

Form 10-Q

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Unaudited Condensed Consolidated Balance Sheets – June 30, 2011 and December 31, 2010		3

	Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010		4

	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2011 and 2010		5

	Unaudited Condensed Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2011 and 2010		6

	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		7

	Notes to Unaudited Condensed Consolidated Financial Statements		8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		36

Item 4.	Controls and Procedures		36

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		36

Item 1A.	Risk Factors		36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		36

Item 3.	Defaults upon Senior Securities		36

Item 4.	(Removed and Reserved)		36

Item 5.	Other Information		36

Item 6.	Exhibits		37

SIGNATURES			38

-2-

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)


	June 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,434		$	5,762
Accounts receivable - trade, net		225,776			171,550
Inventories		88,820			55,428
Other		22,212			19,798

Total current assets		342,242			252,538

FIXED ASSETS, at cost		374,284			373,339
Less: Accumulated depreciation		(117,809	)		(108,283	)

Net fixed assets		256,475			265,056

NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income		165,983			168,438
EQUITY INVESTEES		335,404			343,434
INTANGIBLE ASSETS, net of amortization		108,663			120,175
GOODWILL		325,046			325,046
OTHER ASSETS, net of amortization		28,950			32,048


TOTAL ASSETS	$	1,562,763		$	1,506,735


LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	202,332		$	165,978
Accrued liabilities		42,998			40,736

Total current liabilities		245,330			206,714

SENIOR SECURED CREDIT FACILITIES		406,000			360,000
SENIOR UNSECURED NOTES		250,000			250,000
DEFERRED TAX LIABILITIES		14,247			15,193
OTHER LONG-TERM LIABILITIES		5,723			5,564
COMMITMENTS AND CONTINGENCIES (Note 12)

PARTNERS’ CAPITAL:
Common unitholders, 64,615 units issued and outstanding at June 30, 2011 and December 31, 2010, respectively		641,463			669,264


TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,562,763		$	1,506,735

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

-3-

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
REVENUES:
Supply and logistics	$	698,343		$	404,892		$	1,326,140		$	828,263
Refinery services		49,363			38,221			96,909			67,723
Pipeline transportation services		15,084			13,425			29,539			27,083

Total revenues		762,790			456,538			1,452,588			923,069

COSTS AND EXPENSES:
Supply and logistics product costs		653,544			369,228			1,250,683			761,419
Supply and logistics operating costs		25,813			23,763			50,038			47,629
Refinery services operating costs		30,264			21,790			59,850			38,017
Pipeline transportation operating costs		4,356			3,113			8,426			7,542
General and administrative		8,380			6,801			16,434			13,095
Depreciation and amortization		14,253			13,606			28,156			27,012
Net loss (gain) on disposal of surplus assets		249			(62	)		238			18

Total costs and expenses		736,859			438,239			1,413,825			894,732


OPERATING INCOME		25,931			18,299			38,763			28,337
Equity in earnings of equity investees		592			363			3,789			545
Interest expense		(9,011	)		(3,760	)		(17,710	)		(6,964	)

Income before income taxes		17,512			14,902			24,842			21,918
Income tax expense		(154	)		(981	)		(454	)		(1,672	)


NET INCOME		17,358			13,921			24,388			20,246

Net loss attributable to noncontrolling interests		—			317			—			877

NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	17,358		$	14,238		$	24,388		$	21,123


NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. PER COMMON UNIT:
Basic and Diluted	$	0.27		$	0.29		$	0.38		$	0.36

WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted		64,615			39,586			64,615			39,567

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

-4-

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME

(In thousands)


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

Net income	$	17,358	$	13,921	$	24,388	$	20,246
Change in fair value of derivatives:
Current period reclassification to earnings		—		279		—		559
Changes in derivative financial instruments - interest rate swaps		—		4		—		(200	)

Comprehensive income		17,358		14,204		24,388		20,605
Comprehensive loss attributable to noncontrolling interests		—		172		—		694

Comprehensive income attributable to Genesis Energy, L.P.	$	17,358	$	14,376	$	24,388	$	21,299

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

-5-

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)


	Partners’ Capital
	Number of Common Units		Common Unitholders

Partners’ capital, December 31, 2010		64,615	$	669,264
Net income		—		24,388
Cash distributions		—		(52,189	)

Partners’ capital, June 30, 2011		64,615	$	641,463


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

Partners’ capital, December 31, 2009		39,488	$	585,554		$	11,152		$	(829	)	$	23,056		$	618,933
Comprehensive income:
Net income		—		14,770			6,353			—			(877	)		20,246
Interest rate swap loss reclassified to interest expense		—		—			—			274			285			559
Interest rate swap loss		—		—			—			(98	)		(102	)		(200	)
Cash contributions		—		—			37			—			—			37
Cash distributions		—		(28,799	)		(4,964	)		—			(3	)		(33,766	)
Contribution for executive compensation		—		—			(1,676	)		—			—			(1,676	)
Unit based compensation expense		98		20			—			—			—			20

Partners’ capital, June 30, 2010		39,586	$	571,545		$	10,902		$	(653	)	$	22,359		$	604,153

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

-6-

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	24,388		$	20,246
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization		28,156			27,012
Amortization and write-off of credit facility issuance costs		1,310			1,269
Amortization of unearned income and initial direct costs on direct financing leases		(8,672	)		(8,873	)
Payments received under direct financing leases		10,926			10,926
Equity in earnings of investments in equity investees		(3,789	)		(545	)
Cash distributions of earnings of equity investees		5,917			1,122
Non-cash effect of equity-based compensation plans		(757	)		72
Non-cash compensation credit		—			(1,676	)
Deferred and other tax liabilities		21			414
Unrealized gain on derivative transactions		(15	)		(1,105	)
Other, net		972			303
Net changes in components of operating assets and liabilities (See Note 9)		(49,035	)		(38,452	)

Net cash provided by operating activities		9,422			10,713

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets		(9,328	)		(5,980	)
Cash distributions received from equity investees - return of investment		6,096			180
Investments in equity investees		(194	)		—
Other, net		1,041			640

Net cash used in investing activities		(2,385	)		(5,160	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		267,900			345,029
Bank repayments		(221,900	)		(307,029	)
Credit facility issuance fees		—			(7,428	)
General partner contributions		—			37
Noncontrolling interests contributions, net of distributions		—			(3	)
Distributions to common unitholders		(52,189	)		(28,799	)
Distributions to general partner interest		—			(4,964	)
Other, net		(1,176	)		(511	)

Net cash used in financing activities		(7,365	)		(3,668	)


Net (decrease) increase in cash and cash equivalents		(328	)		1,885
Cash and cash equivalents at beginning of period		5,762			4,148


Cash and cash equivalents at end of period	$	5,434		$	6,033

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

-7-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

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

•

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

•

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

•

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

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

On December 28, 2010, we permanently eliminated our IDRs and converted our 2% general partner interest into a non-economic interest, which we refer to as our IDR Restructuring. We issued Class A Units, Class B Units and Waiver Units to the former stakeholders of our general partner in exchange for the elimination of our IDRs. See additional information on our outstanding equity in Note 6.

Basis of Presentation and Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries, and Genesis Energy, LLC, our general partner. The inclusion of Genesis Energy, LLC in our Consolidated Financial Statements was effective December 28, 2010 due to our IDR Restructuring.

Our 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 condensed 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, 2010.

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.

-8-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2. Inventories

The major components of inventories were as follows:


	June 30, 2011		December 31, 2010
Crude oil	$	15,219	$	6,128
Petroleum products		59,460		38,588
Caustic soda		6,869		6,309
NaHS		7,245		4,387
Other		27		16

Total inventories	$	88,820	$	55,428

Inventories are valued at the lower of cost or market. The costs of inventories exceeded market values by approximately $0.4 million at June 30, 2011, and we reduced the value of inventory in our unaudited condensed consolidated financial statements for this difference. At December 31, 2010, market values of our inventories exceeded recorded costs.

3. Equity Investees

We are accounting for our 50% ownership in Cameron Highway Oil Pipeline Company (“Cameron Highway”) under the equity method of accounting.

The following table reflects summarized income statement information for Cameron Highway for only the three and six months ended June 30, 2011 as we did not acquire our 50% equity interest in Cameron Highway until November 23, 2010.


	Three Months Ended June 30, 2011		Six Months Ended June 30, 2011
Revenues	$	9,835	$	24,844
Operating Income	$	2,783	$	11,192
Net Income	$	2,783	$	11,202

-9-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Intangible Assets and Goodwill

Intangible Assets

The following table reflects the components of intangible assets being amortized as of:


	June 30, 2011						December 31, 2010
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery services customer relationships	$	94,654	$	57,625	$	37,029	$	94,654	$	53,139	$	41,515
Supply and logistics customer relationships		35,430		21,783		13,647		35,430		19,981		15,449
Refinery services supplier relationships		36,469		32,791		3,678		36,469		31,476		4,993
Refinery services licensing agreements		38,678		17,631		21,047		38,678		15,786		22,892
Supply and logistics trade names - Davison and Grifco		18,888		11,353		7,535		18,888		7,530		11,358
Intangibles associated with supply and logistics lease		13,260		1,855		11,405		13,260		1,618		11,642
Other		16,911		2,589		14,322		13,776		1,450		12,326

Total	$	254,290	$	145,627	$	108,663	$	251,155	$	130,980	$	120,175

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


Year Ended December 31,		Amortization Expense to be Recorded
Remainder of 2011		$14,498
2012		$21,914
2013		$14,312
2014		$12,049
2015		$10,247

In the first quarter of 2011, we adjusted the useful lives of our supply and logistics trade names. As a result of this change in the amortization period of our assets, operating income and net income attributable to us for the three and six months ended June 30, 2011 decreased $1.4 million, or $0.02 per common unit and $2.9 million, or $0.04 per common unit, respectively. The impact of this change on net income for the remainder of 2011 and 2012 is expected to total $2.8 million and $2.3 million, respectively, and not be material in future periods. The table of estimated future amortization expense above reflects this change.

Goodwill

The carrying amount of goodwill by business segment at both June 30, 2011 and December 31, 2010 was $301.9 million to refinery services and $23.1 million to supply and logistics.

5. Debt

As of June 30, 2011, we had $406 million borrowed under our senior secured credit facility, with $70.4 million of that amount designated as a loan under the inventory sublimit. Additionally, we had $5.9 million in letters of credit outstanding. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 30, 2015. The total amount available for borrowings at June 30, 2011 was $113.1 million under our credit facility.

-10-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We believe the amounts included in our balance sheet for debt outstanding under our senior secured credit facility approximate fair value as interest rates reflect current market rates. At June 30, 2011, $250 million of senior unsecured notes were outstanding, which had a fair value of approximately $248.8 million.

We believe we were in compliance with the financial covenants contained in our credit facility and indenture as of June 30, 2011.

6. Partners’ Capital, Distributions and Net Income Per Common Unit

Partners’ Capital

At June 30, 2011 and December 31, 2010, our outstanding equity consisted of 64,575,065 Class A Units and 39,997 Class B Units. Additionally 6,949,004 Waiver Units were outstanding. On July 20, 2011, we issued 7,350,000 Class A Units in a public offering. We received proceeds, net of underwriting discount, of $185 million from the offering.

Distributions

We paid or will pay the following distributions in 2010 and 2011:


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

Fourth quarter 2009	February 2010	$	0.3600	$	14,251	$	291	$	2,037	$	16,579
First quarter 2010	May 2010	$	0.3675	$	14,548	$	297	$	2,339	$	17,184
Second quarter 2010	August 2010	$	0.3750	$	14,845	$	303	$	2,642	$	17,790
Third quarter 2010	November 2010	$	0.3875	$	15,339	$	313	$	3,147	$	18,799
Fourth quarter 2010	February 2011	$	0.4000	$	25,846	$	—	$	—	$	25,846
First quarter 2011	May 2011	$	0.4075	$	26,343	$	—	$	—	$	26,343
Second quarter 2011	August 2011 ⁽¹⁾	$	0.4150	$	29,866	$	—	$	—	$	29,866

(1)	This distribution will be paid on August 12, 2011 to unitholders of record as of August 5, 2011. It includes $3.1 million of distributions on the 7,350,000 Class A Common Units issued in July 2011.

-11-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Net Income Per Common Unit

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2011		2010			2011		2010
Numerators for basic and diluted net income per common unit:
Income attributable to Genesis Energy, L.P.	$	17,358	$	14,238		$	24,388	$	21,123
Less: General partner’s incentive distribution to be paid for the period		—		(2,642	)		—		(4,981	)
Add: Expense (Credit) for Class B Awards		—		301			—		(1,676	)

Subtotal		17,358		11,897			24,388		14,466
Less: General partner 2% ownership		—		(238	)		—		(289	)

Income available for common unitholders	$	17,358	$	11,659		$	24,388	$	14,177


Denominator for basic and diluted per common unit:		64,615		39,586			64,615		39,567


Basic and diluted net income per common unit	$	0.27	$	0.29		$	0.38	$	0.36

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 equity investees. Our segment margin definition also excludes the non-cash effects of our stock appreciation rights compensation plan, 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.

In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO₂ marketing activities and processing of syngas through a joint venture, formerly reported in the Industrial Gases Segment, are now included in our Supply and Logistics Segment. The change in operating segments had no impact on our reportable units for goodwill purposes. The historical segment disclosures have been recast to be consistent with the current presentation. This recast also included combining revenues and costs and expenses for our industrial gases activities shown separately in our Unaudited Condensed Consolidated Statements of Operations in the 2010 period with revenues and costs and expenses for our supply and logistics activities.

-12-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended June 30, 2011
Segment margin ^(a)	$	16,927	$	18,947		$	11,799		$	47,673


Maintenance capital expenditures	$	39	$	160		$	411		$	610


Revenues:
External customers	$	12,051	$	51,334		$	699,405		$	762,790
Intersegment ^(b)		3,033		(1,971	)		(1,062	)		—

Total revenues of reportable segments	$	15,084	$	49,363		$	698,343		$	762,790

Three Months Ended June 30, 2010
Segment margin ^(a)	$	11,437	$	16,190		$	10,222		$	37,849


Maintenance capital expenditures	$	78	$	356		$	484		$	918


Revenues:
External customers	$	11,498	$	40,348		$	404,692		$	456,538
Intersegment ^(b)		1,927		(2,127	)		200			—

Total revenues of reportable segments	$	13,425	$	38,221		$	404,892		$	456,538

-13-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Six Months Ended June 30, 2011
Segment margin ^(a)	$	34,609	$	36,895		$	25,324		$	96,828


Maintenance capital expenditures	$	226	$	367		$	796		$	1,389


Revenues:
External customers	$	24,644	$	100,917		$	1,327,027		$	1,452,588
Intersegment ^(b)		4,895		(4,008	)		(887	)		—

Total revenues of reportable segments	$	29,539	$	96,909		$	1,326,140		$	1,452,588


Six Months Ended June 30, 2010
Segment margin ^(a)	$	21,836	$	29,450		$	17,228		$	68,514


Maintenance capital expenditures	$	134	$	815		$	594		$	1,543


Revenues:
External customers	$	22,910	$	71,718		$	828,441		$	923,069
Intersegment ^(b)		4,173		(3,995	)		(178	)		—

Total revenues of reportable segments	$	27,083	$	67,723		$	828,263		$	923,069

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010

Segment margin	$	47,673		$	37,849		$	96,828		$	68,514
Corporate general and administrative expenses		(7,689	)		(5,975	)		(15,073	)		(11,405	)
Depreciation and amortization		(14,253	)		(13,606	)		(28,156	)		(27,012	)
Net (loss) gain on disposal of surplus assets		(249	)		62			(238	)		(18	)
Interest expense		(9,011	)		(3,760	)		(17,710	)		(6,964	)
Non-cash expenses not included in segment margin		7,102			1,559			(333	)		1,335
Other items excluded from income affecting segment margin		(6,061	)		(1,227	)		(10,476	)		(2,532	)

Income before income taxes	$	17,512		$	14,902		$	24,842		$	21,918

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

-14-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED 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:


	Six Months Ended June 30,
	2011		2010

Petroleum products sales to an affiliate of the Robertson Group	$	21,254	$	—
Marine operating fuel and expenses provided by an affiliate of the Robertson Group		1,820		1,333
Sales of CO₂ to Sandhill		975		1,308
Petroleum products sales to Davison family businesses		487		464
Operations, general and administrative services provided by our general partner ⁽¹⁾		—		23,131
Truck transportation services provided to Denbury		—		182
Pipeline transportation services provided to Denbury		—		1,365
Payments received under direct financing leases from Denbury		—		99
Pipeline transportation income portion of direct financing lease fees from Denbury		—		1,502
Pipeline monitoring services provided to Denbury		—		10
CO₂ transportation services provided by Denbury		—		373

(1)	Our general partner became a wholly-owned subsidiary in December 2010.

Amounts due to and from Related Parties

At June 30, 2011 and December 31, 2010, an affiliate of the Robertson Group owed us $0.7 million and $1.4 million, respectively, for petroleum products purchases, and we owed the affiliate $0.1 million and $0.2 million, respectively, for marine-related costs. Sandhill owed us $0.2 million for purchases of CO₂ at June 30, 2011 and December 31, 2010.

-15-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Supplemental Cash Flow Information

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


	Six Months Ended June 30,
	2011			2010
Decrease (increase) in:
Accounts receivable	$	(54,810	)	$	4,870
Inventories		(33,847	)		(45,008	)
Other current assets		(1,727	)		(1,042	)
Increase (decrease) in:
Accounts payable		37,167			5,302
Accrued liabilities		4,182			(2,574	)

Net changes in components of operating assets and liabilities	$	(49,035	)	$	(38,452	)

Payments of interest and commitment fees were $17.6 million and $6.1 million for the six months ended June 30, 2011 and 2010, respectively.

At June 30, 2011, we had incurred liabilities for fixed asset and intangible asset additions totaling $0.9 million that had not been paid at the end of the second quarter, and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” under investing activities on the Unaudited Condensed Consolidated Statements of Cash Flows. At June 30, 2010, we had incurred $1.1 million of such liabilities that had not been paid at that date and are not included in “Payments to acquire fixed and intangible assets” and “Other, net” under investing activities.

10. Derivatives

Commodity Derivatives

At June 30, 2011, we had the following outstanding derivative commodity futures, forwards and options contracts that were entered into to hedge inventory or fixed price purchase commitments. We had no outstanding derivative contracts that were designated as hedges under accounting rules.

-16-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		193		101
Weighted average contract price per bbl	$	95.37	$	97.06

Heating oil futures:
Contract volumes (1,000 bbls)		305		56
Weighted average contract price per gal	$	2.97	$	2.91

RBOB gasoline futures:
Contract volumes (1,000 bbls)		60		—
Weighted average contract price per gal	$	2.81	$	—

#6 Fuel oil futures:
Contract volumes (1,000 bbls)		436		18
Weighted average contract price per bbl	$	96.26	$	97.77

Crude oil forwards:
Contract volumes (1,000 bbls)		31		31
Weighted average contract price per bbl	$	96.34	$	109.55

Crude oil written calls:
Contract volumes (1,000 bbls)		110		—
Weighted average premium received	$	4.50	$	—

-17-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial Statement Impacts

The following tables reflect the estimated fair value gain (loss) position of our hedge derivatives and related inventory impact for qualifying hedges at June 30, 2011 and December 31, 2010:

Fair Value of Derivative Assets and Liabilities


	Asset Derivatives
	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
		June 30, 2011			December 31, 2010
Commodity derivatives - futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other Current Assets	$	—		$	14
Undesignated hedges	Other Current Assets		1,104			493

Total asset derivatives		$	1,104		$	507


	Liability Derivatives
	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
		June 30, 2011			December 31, 2010
Commodity derivatives - forwards futures and call options:
Hedges designated under accounting guidance as fair value hedges	Other Current Assets	$	—		$	(191	) ⁽¹⁾
Undesignated hedges	Other Current Assets		(2,600	) ⁽¹⁾		(2,283	) ⁽¹⁾

Total liability derivatives			(2,600	)		(2,474	)

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

-18-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Effect on Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income
	Amount of Gain (Loss) Recognized in Income
	Supply & Logistics Product Costs						Interest Expense Reclassified from AOCL					Other Comprehensive Loss Effective Portion
	Three Months Ended June 30,						Three Months Ended June 30,					Three Months Ended June 30,
	2011			2010			2011		2010			2011		2010
Commodity derivatives - forwards futures and call options:
Contracts designated as hedges under accounting guidance	$	(173	) ⁽¹⁾	$	1,032	⁽¹⁾	$	—	$	—		$	—	$	—
Contracts not considered hedges under accounting guidance		(13,637	)		4,977			—		—			—		—

Total commodity derivatives		(13,810	)		6,009			—		—			—		—

Interest rate swaps designated as cash flow hedges under accounting guidance		—			—			—		(279	)		—		4

Total derivatives	$	(13,810	)	$	6,009		$	—	$	(279	)	$	—	$	4


	Effect on Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income
	Amount of Gain (Loss) Recognized in Income
	Supply & Logistics Product Costs						Interest Expense Reclassified from AOCL					Other Comprehensive Loss Effective Portion
	Six Months Ended June 30,						Six Months Ended June 30,					Six Months Ended June 30,
	2011			2010			2011		2010			2011		2010
Commodity derivatives - forwards futures and call options:
Contracts designated as hedges under accounting guidance	$	(434	) ⁽¹⁾	$	1,306	⁽¹⁾	$	—	$	—		$	—	$	—
Contracts not considered hedges under accounting guidance		(31,890	)		4,425			—		—			—		—

Total commodity derivatives		(32,324	)		5,731			—		—			—		—

Interest rate swaps designated as cash flow hedges under accounting guidance		—			—			—		(559	)		—		(200	)

Total derivatives	$	(32,324	)	$	5,731		$	—	$	(559	)	$	—	$	(200	)

(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 $0.2 million and $0.8 million for the three and six months ended June 30, 2011 and excludes the loss recorded on the hedged inventory of $0.4 million and $0.3 million for the three and six months ended June 30, 2010.

-19-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. 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 June 30, 2011. 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 June 30, 2011								Fair Value at December 31, 2010
Recurring Fair Value Measures	Level 1			Level 2			Level 3		Level 1			Level 2		Level 3

Commodity derivatives:
Assets	$	1,104		$	—		$	—	$	507		$	—	$	—
Liabilities	$	(2,225	)	$	(375	)	$	—	$	(2,474	)	$	—	$	—

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

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are: (i) observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values consist of forward commodity derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations.

Level 3

At June 30, 2011 and December 31, 2010, we had no Level 3 fair value measurements.

At June 30, 2010, our interest rate swaps were included within Level 3 of the fair value hierarchy. These swaps were settled in July 2010 in connection with the acquisition of the 51% of DG Marine we did not own and the termination of DG Marine’s credit facility. 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 June 30,			Six Months Ended June 30,
	2010			2010
Balance at beginning of period		(1,612	)		(1,688	)
Realized and unrealized gains (losses)-
Reclassified into interest expense for settled contracts		279			559
Included in other comprehensive income		4			(200	)

Balance at end of period	$	(1,329	)	$	(1,329	)




Total amount of losses included in earnings attributable to the change in unrealized losses relating to liabilities still held at June 30, 2010				$	(10	)

-20-

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

See Note 10 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.

12. 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 effect on our financial position, results of operations, or cash flows.

13. Subsequent Event – Acquisition of Barges and Pushboats from Florida Marine

In the third quarter of 2011, we expect to complete a transaction to acquire, for $141 million, the black oil transportation fleet of Florida Marine Transporters, Inc. and its affiliates (FMT). The fleet consists of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 push/tow boats which transport heavy refined products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States. We expect to fund that acquisition with the proceeds of a public offering of our common units. On July 20, 2011, we issued 7,350,000 Class A Common Units, and received $185 million in proceeds, net of underwriting discounts. The remaining net proceeds of the offering were used for other purposes, including the repayment of borrowings outstanding under our credit facility.

-21-

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

•

Segment Reporting Change

•

Available Cash before Reserves

•

Results of Operations

•

Liquidity and Capital Resources

•

Non-GAAP Reconciliation

•

Commitments and Off-Balance Sheet Arrangements

•

Forward Looking Statements

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 equity investees. In addition, our segment margin definition excludes the non-cash effects of our stock appreciation rights plan, 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 Condensed 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 distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring assets that provide new sources of cash flows, the elimination of earnings of DG Marine in excess of distributable cash until July 29, 2010 when DG Marine’s credit facility was repaid, 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 its most directly comparable GAAP measure of cash provided by operating activities, see “Liquidity and Capital Resources - Non-GAAP Reconciliation” below.

Overview

In the second quarter of 2011, we reported net income attributable to the partnership of $17.4 million, or $0.27 per common unit. We generated $31.9 million of Available Cash before Reserves. In August 2011, we will distribute $0.415 per common unit to our unitholders with respect to the second quarter. During the second quarter of 2011, cash provided by operating activities was $11.5 million.

Segment margin increased by $9.8 million, or 26%, in the second quarter of 2011, as compared to the second quarter of 2010. This increase resulted from improvements in segment margin of approximately 48%, 17% and 15% in our pipeline transportation, refinery services and supply and logistics segments, respectively. The contribution to segment margin from our investment in Cameron Highway, combined with increased throughput on our onshore pipelines, were the primary factors increasing pipeline segment margin. Our refinery services segment margin increased as a result of several factors, including operating efficiencies realized at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations. Our supply and logistics segment, which now includes the results of our CO₂ marketing and other industrial gases activities, benefited from market conditions that increased the differentials between grades of crude oil and increased demand for heavy-end petroleum products.

-22-

In the third quarter of 2011 we expect to complete the previously announced transaction to acquire, for $141 million, the black oil barge transportation fleet of Florida Marine Transporters, Inc. and its affiliates (FMT). That fleet is primarily comprised of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 push/tow boats which transport heavy refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. The barges, which have an average age of approximately three years, are double-hulled and fully compliant with the requirements of the Oil Pollution Act. The boats are modern and efficient, 13 of which have been in service three years or less.

This acquisition will complement and further integrate certain of our existing operations, including our DG Marine inland barge business (comprised of 20 barges and 10 push/tow boats), our storage and blending terminals and our crude oil pipeline systems. All of the expanded fleet of 50 barges are capable of transporting heavy refined products, including asphalt, and with minor modifications, half of the barges will be capable of transporting crude oil as well. We funded this transaction with funds raised from a sale of 7.4 million Class A Common Units that closed on July 20, 2011. See additional discussion under Liquidity and Capital Resources – Capital Resources/Sources of Cash below.

On July 13, 2011, we increased our quarterly distribution rate to our common unitholders for the twenty-fourth consecutive quarter. In August of 2011, we will pay a distribution of $0.4150 per unit attributable to our second quarter of 2011, which represents an approximate 10.7% increase from our distribution of $0.375 per unit for the second quarter of 2010. During the second quarter of 2011, we paid a distribution of $0.4075 per unit related to the first quarter of 2011.

Segment Reporting Change

In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO₂ marketing activities and processing of syngas through a joint venture, formerly reported in the Industrial Gases Segment, are now included in our Supply and Logistics Segment. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

-23-

Available Cash before Reserves

Available Cash before Reserves was as follows:


	Three Months Ended June 30,
	2011			2010
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	17,358		$	14,238
Depreciation and amortization		14,253			13,606
Cash received from direct financing leases not included in income		1,141			1,038
Cash effects of sales of certain assets		1,413			795
Effects of available cash generated by equity method investees not included in income		4,921			188
Cash effects of equity-based compensation plans		(716	)		(117	)
Non-cash tax expense		(124	)		228
Loss of DG Marine in excess of distributable cash		—			(1,481	)
Non-cash equity-based compensation (benefit) expense		(270	)		246
Expenses related to acquiring or constructing assets that provide new sources of cash flow		1,466			81
Unrealized gains on derivative transactions excluding fair value hedges		(6,968	)		(1,591	)
Other items, net		80			(238	)
Maintenance capital expenditures		(610	)		(918	)

Available Cash before Reserves	$	31,944		$	26,075

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 June 30, 2011 and 2010 in “Liquidity and Capital Resources – Non-GAAP Reconciliation” below. For the three months ended June 30, 2011, cash flows provided by operating activities were $11.5 million and for the three months ended June 30, 2010, cash flows utilized in operating activities were $2.6 million.

Results of Operations

Revenues, Costs and Expenses and Net Income

Our revenues for the three months ended June 30, 2011 increased $306 million, or 67% from the second quarter of 2010. Additionally, our costs and expenses increased $299 million, or 68% 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 second quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products. In the second quarter of 2011, closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $102.56 per barrel, as compared to $78.04 per barrel in the second quarter of 2010 – an increase of 31.4%.

Net income (attributable to us) increased $3.1 million, or 22%, between the second quarter of 2010 and the same period in 2011. The significant factors affecting net income were improved operating results by our business segments as compared to the second quarter of 2010 including our equity method investees, offset partially by an increase in interest costs and general and administrative expenses. A more detailed discussion of our segment results and other costs is included below.

-24-

Our revenues for the six months ended June 30, 2011 increased $530 million, or 57% from the six months ended June 30, 2010. Additionally, our costs and expenses increased $519 million, or 58% between the two periods. This increase in our revenues and costs between the two periods is primarily due to fluctuations in the market prices for crude oil and petroleum products. In the first half of 2011, average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $98.33 per barrel, as compared to $78.37 per barrel in the first half of 2010 – an increase of 25.5%. Net income (attributable to us) increased $3.3, or 15%, between the first half of 2010 and the same period in 2011, with the majority of the increase attributable to improved segment results, partially offset by increased general and administrative expenses and increases in depreciation and amortization expense as discussed below.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2011 and 2010 was as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)				(in thousands)
Pipeline transportation	$	16,927	$	11,437	$	34,609	$	21,836
Refinery services		18,947		16,190		36,895		29,450
Supply and logistics		11,799		10,222		25,324		17,228

Total Segment Margin	$	47,673	$	37,849	$	96,828	$	68,514

Pipeline Transportation Segment

Operating results and volumetric data for our pipeline transportation segment were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)

Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	5,867		$	4,896		$	11,200		$	9,412
CO₂ tariffs and revenues from direct financing leases of CO₂ pipelines		6,212			6,263			12,858			12,951
Sales of crude oil pipeline loss allowance volumes		2,109			1,533			3,628			2,872
Available cash generated by Cameron Highway		5,000			—			11,000			—
Pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses		(3,662	)		(2,534	)		(6,733	)		(5,943	)
Payments received under direct financing leases not included in income		1,141			1,038			2,254			2,053
Other		260			241			402			491

Segment margin	$	16,927		$	11,437		$	34,609		$	21,836

-25-


	Three Months Ended June 30,				Six Months Ended June 30,
Pipeline System	2011		2010		2011		2010

Mississippi - Bbls/day		21,133		23,493		20,883		23,789
Jay - Bbls/day		16,655		14,400		15,803		14,493
Texas - Bbls/day		47,091		27,902		46,971		23,602
Cameron Highway - Bbls/day		108,964		—		139,666		—
Free State - Mcf/day		131,683		133,009		153,220		154,013

Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010

Pipeline Segment Margin for the second quarter of 2011 increased $5.5 million. The significant components of this change were as follows:

•

Our share of the available cash before reserves generated by Cameron Highway was $5.0 million for the three months ended June 30, 2011. We acquired our 50% interest in Cameron Highway in November 2010. Revenue generating volumes on Cameron Highway were approximately 108,964 barrels per day, a 36% decrease from the average daily rate for the first quarter of 2011. Planned improvements to offshore field facilities by producers with fields connected to Cameron Highway were performed in the second quarter of 2011 and are expected to continue in the third quarter of 2011. Although these field improvements by the producers are expected to increase volumes on Cameron Highway in the future, reductions in volumes while the improvements are made will likely reduce our share of available cash before reserves from the joint venture during the third quarter.

•

Crude oil tariffs and revenues from direct financing leases increased $1.0 million. Volumes transported on our crude oil pipelines increased 19,084 barrels per day, with the increase in volumes attributable primarily to the Texas System where demand by the refiners connected to our system increased. Volumes on the Jay System increased 2,255 barrels per day, while volumes on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, decreased by 2,360 barrels a day, primarily as a result of fluctuations in tertiary recovery activities by producers.

•

Pipeline operating costs, excluding non-cash charges increased approximately $1.1 million primarily due to increased insurance costs (related to our investment in Cameron Highway) and maintenance expenditures.

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

For the six month periods, Pipeline Segment Margin increased $12.8 million. The primary factors in this increase were as follows:

•

Our share of the available cash before reserves generated by Cameron Highway was $11.0 million for the six months ended June 30, 2011.

•

Crude oil tariffs and revenues from direct financing leases increased $1.8 million. Volumes transported on our crude oil pipelines increased 21,773 barrels per day, with the increase in volumes attributable primarily to the Texas System. Volumes on the Jay system increased 1,310 barrels per day, while volumes on the Mississippi System decreased 2,906 barrels per day. The fluctuations in volumes on our pipeline systems for the six months ended 2011 as compared to the six months ended 2010 are due to similar explanations as provided in the quarter to quarter discussion.

-26-

Refinery Services Segment

Operating results for our refinery services segment were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Volumes sold:
NaHS volumes (Dry short tons “DST”)		36,080			38,307			73,313			71,414
NaOH (caustic soda) volumes (DST)		26,209			23,969			50,849			45,336

Total		62,289			62,276			124,162			116,750


Revenues (in thousands):
NaHS revenues	$	36,459		$	30,517		$	73,258		$	54,771
NaOH (caustic soda) revenues		12,004			6,810			22,243			11,612
Other revenues		2,871			3,021			5,416			5,335

Total external segment revenues	$	51,334		$	40,348		$	100,917		$	71,718


Segment margin	$	18,947		$	16,190		$	36,895		$	29,450


Average index price for NaOH per DST ⁽¹⁾	$	495		$	340		$	468		$	304

Raw material and processing costs as % of segment revenues		41	%		35	%		42	%		32	%

(1)	Source: Harriman Chemsult Ltd.

Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010

Refinery services Segment Margin for the second quarter of 2011 was $18.9 million, an increase of $2.8 million, or 17%, from the comparative period in 2010. The significant components of this fluctuation were as follows:

•

NaHS sales volumes decreased 5.8% between the second quarter periods. Difficulties in mining companies’ negotiations with their workforces led to a slowdown in mine activity and a decrease in our sales volumes to mining companies in the export market.

•

Revenues increased primarily as a function of the increase in the average index price for caustic soda. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations and our logistics management, as discussed below, helped offset these costs.

•

Caustic soda sales volumes increased 9.3%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Index prices for caustic soda averaged approximately $340 per DST in the second quarter of 2010. Market prices of caustic soda increased to an average of approximately $495 per DST during the second quarter of 2011. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we

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generally pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to mitigate the effects of changes in index prices for caustic on our operating costs.

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

•

An increase in NaHS sales volumes of 2.7% increased Segment Margin. The demand for base metals such as copper and molybdenum has increased over the prior period as the world economies, particularly outside of the United States and European Union, have improved over the prior period. Additionally the return of industrialization and urbanization in the world’s emerging economies has increased the demand for paper products and packaging materials. These trends have led to a noticeable increase in NaHS demand from some copper and molybdenum miners and from our pulp/paper customers primarily in North America.

•

An increase in caustic soda sales volumes of 12.2%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Market prices of caustic soda increased to an average of $468 per DST during the first half of 2011 as compared to market prices of caustic soda of $304 per DST in the first half of 2010. The pricing in our sales contracts for NaHS include adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point. However, as discussed above, these changes in caustic soda prices do not materially affect Segment Margin. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although efficiencies gained from our bulk purchases, logistic and storage capabilities helped offset these costs.

Supply and Logistics Segment

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Supply and logistics revenue	$	698,343		$	404,892		$	1,326,140		$	828,263
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions		(660,512	)		(369,228	)		(1,250,977	)		(761,419	)
Operating and segment general and administrative costs, excluding non-cash charges for equity-based compensation and other non-cash expenses		(26,544	)		(25,994	)		(50,851	)		(50,640	)
Other		512			552			1,012			1,024

Segment margin	$	11,799		$	10,222		$	25,324		$	17,228


Volumes of crude oil and petroleum products (barrels per day)		67,469			50,383			67,167			53,799

Three Months Ended June 30, 2011 as Compared to Three Months Ended June 30, 2010

The average market prices of crude oil and petroleum products increased by more than $24 per barrel, or approximately 31.4%, between the two quarterly periods; however that price volatility had a limited impact on our Segment Margin. Segment Margin for our Supply and Logistics segment increased by $1.6 million.

The increase in segment margin resulted primarily from increased opportunities to acquire and re-sell additional volumes of heavy-end petroleum products as refining activity increased in the 2011 period in our operating area. The volumes we handled during the period increased by 34% as compared to the second quarter of 2010. Greater demand for fuel oil and other heavy-end petroleum products in countries outside the United States has helped sustain the price environment for the products we sell.

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In addition, favorable differentials between different grades of crude oil and petroleum products as well as changes we made in some of our existing crude oil and petroleum products commercial arrangements increased Segment Margin.

The increase in Segment Margin in the second quarter was partially offset by the effects of the Mississippi River flooding, which impaired our petroleum products marketing and marine transportation activities and resulted in some increased costs for idle time.

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Segment margin for our Supply and Logistics segment increased $8.1 million between the six month periods. Average market prices of crude oil and petroleum products increased by approximately $20 per barrel, or approximately 25.5%, however, as previously discussed, price volatility has a limited impact on our Segment Margin.

Favorable quality differentials, primarily between grades of crude oil, as well as modifications to our existing crude oil and petroleum products commercial arrangements, were key factors resulting in increased Segment Margin.

Similar to the quarter-to-quarter comparison, Segment Margin for the six month period also increased due to greater availability of volumes of heavy-end petroleum products resulting from increased refinery utilization in our operating area. The volumes we handled during the first half of 2011 increased approximately 25% as compared to the first half of 2010 as higher foreign demand for fuel oil and other heavy-end petroleum products helped sustain the price environment for the products we sell.

As indicated above in the three-month 2011 period, the Mississippi River flooding during the second quarter impaired our petroleum products marketing and marine transportation activities and increased some of our costs.

Other Costs, Interest, and Income Taxes

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)				(in thousands)

General and administrative expenses not separately identified below	$	5,165	$	5,175	$	10,306	$	10,037
Bonus plan expense		1,513		1,306		2,963		2,306
Equity-based compensation plan expense		236		19		644		666
Third party costs related to business development activities and growth projects		1,466		—		2,521		—
Expenses related to change in owner of our general partner		—		—		—		1,762
Non-cash compensation expense (credit) related to management team		—		301		—		(1,676	)

Total general and administrative expenses	$	8,380	$	6,801	$	16,434	$	13,095

Routine general and administrative expenses were relatively consistent between the three and six month periods. Our bonus plan expenses increased $0.2 million and $0.7 million for the three and six months ended June 30, 2011, respectively, related to a higher level of bonus accrual as a result of improvements in our operating results. An increase in activities evaluating potential business and growth opportunities resulted in an increase of approximately $1.5 million and $2.5 million, for the three and six month periods, respectively, for costs paid to third parties for their assistance in these activities.

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Depreciation and amortization expense. Depreciation and amortization expense increased $0.6 million and $1.1 million between the three and six month periods, respectively primarily as a result of an adjustment in the useful lives of certain of our intangible assets in the first quarter of 2011. See Note 4 to our Unaudited Condensed Consolidated Financial Statements for additional information regarding this change.

Interest expense, net.

Interest expense, net was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)

Genesis Facility and Notes:
Interest expense, credit facility, including commitment fees	$	3,383		$	2,065		$	6,509		$	3,989
Interest expense, senior unsecured notes		4,976			—			9,898			—
Amortization of credit facility and notes issuance fees		655			165			1,310			328
Write-off of facility fees		—			402			—			402
DG Marine Facility:
Interest expense and commitment fees		—			1,143			—			2,274
Interest income		(3	)		(15	)		(7	)		(29	)

Net interest expense	$	9,011		$	3,760		$	17,710		$	6,964

Interest expense on our credit facility increased as our average debt balance increased $52.5 million between the quarterly periods and $50.4 million between the six-month periods. The average interest rate for borrowed funds increased approximately 1% over the same periods, from 2.2% to 3.2%. The increase in the outstanding balance under our credit facility is attributable primarily to acquisitions in the second half of 2010. Additionally, when we amended and extended our credit facility in June 2010, our average interest rate increased to reflect market conditions.

We also incurred interest expense, including amortization of notes issuance fees, of $5.2 million and $10.3 million during the quarter and first six months of 2011, respectively in connection with the $250 million of senior unsecured notes issued in November 2010 to partially finance our acquisition of a 50% equity interest in Cameron Highway.

Interest expense in the first half of 2010 was also affected by interest on the DG Marine credit facility. In the second half of 2010, we eliminated this facility with borrowings under our credit facility.

Income tax expense. A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

Liquidity and Capital Resources

General

As of June 30, 2011, we believe our balance sheet and liquidity position remained strong. We had $113.1 million of borrowing capacity available under our $525 million senior secured bank revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our short-term capital needs.

We continue to pursue a growth strategy that requires significant capital.

In the third quarter of 2011, we expect to complete the previously-announced acquisition of the black oil barge transportation fleet of Florida Marine Transporters, Inc. and its affiliates for $141 million. That fleet is

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primarily comprised of 30 barges and 14 push boats which transport heavy refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers.

On April 11, 2011, we announced plans to expand our crude oil infrastructure in Texas through the acquisition and refurbishment of three crude oil tanks with barge dock access, and to increase our refinery services operating footprint to provide services to a refinery in Tulsa, Oklahoma.

Capital Resources

Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, including through equity and debt offerings (public and private) from time to time and other financing transactions, to 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.

In July 2011, we issued 7,350,000 Class A common units at $26.30, providing total net proceeds, after deducting underwriting discounts and commissions and estimated offering expenses, of approximately $184.9 million. We will use $141 million of the proceeds from this offering to fund the purchase price and related transaction costs for our acquisition of the black oil barge transportation business of Florida Marine Transporters, Inc. and its affiliates. The remaining net proceeds of the offering were used for other purposes, including the repayment of borrowings outstanding under our credit facility.

Our credit facility is a $525 million senior secured revolving credit facility maturing on June 30, 2015. It includes an accordion feature whereby the total credit available can be increased up to $650 million for acquisitions or internal growth projects, with lender approval. Among other modifications, our credit facility also includes a $75 million inventory sublimit tranche. This inventory tranche is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate. Additionally, our restructured credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Twelve lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility.

Our unaudited condensed consolidated balance sheet at June 30, 2011 includes total long-term debt of $656 million, consisting of $406 million outstanding under our credit facility and $250 million of senior unsecured notes due in 2018. Included in the $406 million outstanding under our credit facility is $70.4 million borrowed under the inventory sublimit tranche.

Cash Flows from Operations

We generally 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.

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We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for the crude oil. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of oil. In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.

Net cash flows provided by our operating activities for the six months ended June 30, 2011 were approximately $9.4 million. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash utilized in operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more cash. At June 30, 2011, the cost of the inventory on our balance sheet increased by $33.4 million from December 31, 2010. Sales of inventory in late June that were collected in July 2011, combined with higher market prices, increased net accounts receivable at June 30, 2011 as compared to December 31, 2010.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our acquisition activities, internal growth projects and distributions we pay to our unitholders. We finance internal growth projects and distributions primarily with cash generated by our operations. Acquisition activities have historically been funded with borrowings under our credit facility, equity issuances and the issuance of senior unsecured notes.

Capital Expenditures, and Business and Asset Acquisitions

A summary of our expenditures for fixed assets and other asset acquisitions in the first half of 2011 and 2010 is as follows:


	Six Months Ended June 30,
	2011		2010
	(in thousands)
Capital expenditures for property, plant and equipment:
Maintenance capital expenditures:
Pipeline transportation assets	$	226	$	134
Supply and logistics assets		552		574
Refinery services assets		367		815
Other assets		244		20

Total maintenance capital expenditures		1,389		1,543

Growth capital expenditures:
Pipeline transportation assets		1,456		123
Supply and logistics assets		1,575		433
Refinery services assets		102		—
Information technology systems upgrade project		3,135		4,492

Total growth capital expenditures		6,268		5,048

Total capital expenditures		7,657		6,591

During 2011, we expect to expend approximately $3.0 million to $4.0 million for maintenance capital projects in progress or planned. Those expenditures are expected to include improvements in all of our businesses. In future years we expect to spend $4 million to $5 million per year on maintenance capital projects.

On April 11, 2011, we announced two projects to increase the services we provide to producers and refiners. We acquired three above-ground storage tanks, located in Texas City, Texas, representing aggregate capacity of approximately 230,000 barrels that we will refurbish and convert into crude-oil-capable tanks. We also acquired an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system. We also are constructing a truck station, tankage and possible pipeline interconnections at West Columbia,

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Texas, to be able to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area as well as markets accessible via barge from the new Texas City terminal. Once the refurbishment, tie-in and all interconnecting pipe is completed, estimated to be in the fourth quarter of 2011, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal. In connection with our activities in Texas, we are also constructing interconnecting pipeline and other required facilities to provide transportation services for all of the crude oil production from the Hastings field, near Alvin, Texas, which is in the very early stages of a CO₂ tertiary recovery program.

We also entered into an agreement to install a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in Tulsa, Oklahoma. The new facility, expected to be completed no later than the fourth quarter of 2012, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and result in additional capacity of 24,000 tons per year of NaHS.

We anticipate the total costs of these projects to be less than $30 million in total, which will be incurred primarily in the third and fourth quarters of 2011.

As discussed above, in the third quarter of 2011, we expect to complete the acquisition of the black oil fleet of Florida Marine consisting of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 pushboats for $141 million.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.

Distributions to Unitholders

On August 12, 2011, we will pay a distribution of $0.4150 per common unit with respect to the second quarter of 2011 to common unitholders of record on August 5, 2011. This is the twenty-fourth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 6 to our Unaudited Condensed Consolidated Financial Statements.

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 cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.

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

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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 June 30, 2011 is as follows:


	Three Months Ended June 30,
	2011			2010
	(in thousands)
Net cash flows (used in ) provided by operating activities (GAAP measure)	$	11,527		$	(2,577	)
Adjustments to reconcile operating cash flows to Available Cash before Reserves:
Maintenance capital expenditures		(610	)		(918	)
Proceeds from sales of certain assets		1,164			857
Amortization and write-off of credit facility issuance fees		(655	)		(814	)
Effects of available cash generated by equity method investees not included in cash flows from operating activities		3,813			132
Earnings of DG Marine in excess of distributable cash		—			(1,481	)
Expenses related to acquiring or constructing assets that provide new sources of cash flow		1,466			81
Other items affecting available cash		(1,074	)		503
Net effect of changes in operating accounts not included in calculation of Available Cash		16,313			30,292

Available Cash before Reserves	$	31,944		$	26,075

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, 2010.

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, 2010, 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” as defined under federal law. 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,” ”goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” 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

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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, among others:

•

demand for, the supply of, ,our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids, NaHS and caustic soda and CO₂, 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 on acceptable terms, develop or construct energy infrastructure assets, 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;

•

risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

•

changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations;

•

the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and oil spill in the Gulf;

•

planned capital expenditures and availability of capital resources to fund capital expenditures;

•

our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indenture governing our notes, which contain various affirmative and negative covenants;

•

loss of key personnel;

•

an increase in the competition that our operations encounter;

•

cost and availability of insurance;

•

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

•

our financial and commodity hedging arrangements;

•

capital and credit markets conditions, inflation and interest rates;

•

natural disasters, accidents or terrorism;

•

changes in the financial condition of customers;

•

the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and

•

the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.

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, 2010 and any other risk factors contained in our Current Reports on Form 8-K that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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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 2010 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 10 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

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.

During the first and second quarters of 2011, we substantially completed a staged implementation of a Enterprise Resource Planning system. We changed systems in order to (i) establish a platform that accommodates future acquisitions and growth opportunities (ii) integrate and automate more of our functions, which will allow us to have more information in one integrated database, (iii) to provide operating efficiencies, (iv) to enable us to close our books in a more timely manner without sacrificing quality, (v) to review and improve our processes and (vi) to improve the internal control surrounding our computer systems. As a result of moving to a new system in 2011, many business processes and internal control procedures were required to be changed in order to conform to our new system.

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, 2010. 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, 2010. 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.

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Item 6. Exhibits

(a)

Exhibits.



2.1		Purchase and Sale Agreement (the “Purchase Agreement”), dated June [24], 2011, by and among by and among Florida Marine Transporters, Inc., FMT Heavy Oil Transportation, LLC, FMT Industries, L.L.C., JAR Assets Inc., Pasentine Family Enterprises, LLC, PBC Management, Inc. and GEL Marine, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K dated June 30, 2011, file No. 001-12295)

3.1		Certificate of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Registration Statement on Form S-1, File No. 333-11545)

3.2	*	Amendment to the Certificate of Limited Partnership of Genesis

3.3		Fifth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 3, 2011, File No. 001-12295)

3.4		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, File No. 001-12295)

3.5		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, File No. 001-12295)

3.6		Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295)

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, File No. 001-12295)

10.1	*	Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Executive Phantom Unit with DERs Award - Officers

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

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Schema Document

101.CAL	*	XBRL Calculation Linkbase Document

101.LAB	*	XBRL Label Linkbase Document

101.PRE	*	XBRL Presentation Linkbase Document

101.DEF	*	XBRL Definition Linkbase Document

*	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: August 8, 2011	By:	/s/ ROBERT V. DEERE
		Robert V. Deere Chief Financial Officer

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