GENESIS ENERGY LP - Quarter Report: 2012 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

¨ 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 ý 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 ý 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.



Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨

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

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 1, 2012 was 79,424,522.

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GENESIS ENERGY, L.P.

TABLE OF CONTENTS



		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Partners’ Capital	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
	1. Organization and Basis of Presentation and Consolidation	7
	2. Acquisitions	7
	3. Inventories	8
	4. Fixed Assets and Asset Retirement Obligations	9
	5. Equity Investees	9
	6. Intangible Assets	10
	7. Debt	11
	8. Partner's Capital and Distributions	11
	9. Business Segment Information	12
	10. Transactions with Related Parties	14
	11. Supplemental Cash Flow Information	14
	12. Derivatives	15
	13. Fair-Value Measurements	17
	14. Contingencies	18
	15. Condensed Consolidating Financial Information	18
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	39
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
SIGNATURES		43

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)



	June 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,042		$	10,817
Accounts receivable - trade, net	231,526			237,989
Inventories	72,978			101,124
Other	22,177			26,174
Total current assets	341,723			376,104
FIXED ASSETS, at cost	652,178			541,138
Less: Accumulated depreciation	(139,926		)	(124,213		)
Net fixed assets	512,252			416,925
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	159,982			162,460
EQUITY INVESTEES	547,896			326,947
INTANGIBLE ASSETS, net of amortization	83,525			93,356
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	29,926			30,006
TOTAL ASSETS	$	2,000,350		$	1,730,844
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	189,105		$	199,357
Accrued liabilities	46,676			50,071
Total current liabilities	235,781			249,428
SENIOR SECURED CREDIT FACILITY	445,000			409,300
SENIOR UNSECURED NOTES	350,953			250,000
DEFERRED TAX LIABILITIES	12,110			12,549
OTHER LONG-TERM LIABILITIES	23,204			16,929
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS’ CAPITAL:
Common unitholders, 79,464,519 and 71,965,062 units issued and outstanding at June 30, 2012 and December 31, 2011, respectively	933,302			792,638
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,000,350		$	1,730,844

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES:
Supply and logistics	$	857,127		$	698,343		$	1,722,616		$	1,326,140
Refinery services	48,320			49,363			96,365			96,909
Pipeline transportation services	17,221			15,084			36,630			29,539
Total revenues	922,668			762,790			1,855,611			1,452,588
COSTS AND EXPENSES:
Supply and logistics product costs	792,413			653,544			1,600,508			1,250,683
Supply and logistics operating costs	40,707			25,813			78,623			50,038
Refinery services operating costs	31,050			30,264			61,829			59,850
Pipeline transportation operating costs	5,032			4,356			10,084			8,426
General and administrative	9,967			8,380			19,559			16,434
Depreciation and amortization	15,357			14,253			30,392			28,156
Net loss on disposal of surplus assets	473			249			217			238
Total costs and expenses	894,999			736,859			1,801,212			1,413,825
OPERATING INCOME	27,669			25,931			54,399			38,763
Equity in earnings of equity investees	1,047			592			4,539			3,789
Interest expense	(10,228		)	(9,011		)	(20,824		)	(17,710		)
Income before income taxes	18,488			17,512			38,114			24,842
Income tax benefit (expense)	96			(154		)	74			(454		)
NET INCOME	$	18,584		$	17,358		$	38,188		$	24,388
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.23		$	0.27		$	0.50		$	0.38
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	79,465			64,615			76,150			64,615

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Number of Common Units		Partners’ Capital
	2012	2011	2012			2011
Partners’ capital, January 1	71,965	64,615	$	792,638		$	669,264
Net income	—	—	38,188			24,388
Cash distributions	—	—	(67,445		)	(52,189		)
Issuance of common units for cash, net	5,750	—	169,421			—
Conversion of waiver units	1,738	—	—			—
Other	12	—	500			—
Partners' capital, June 30	79,465	64,615	$	933,302		$	641,463

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	38,188		$	24,388
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	30,392			28,156
Amortization of debt issuance costs and premium	1,784			1,310
Amortization of unearned income and initial direct costs on direct financing leases	(8,456		)	(8,672		)
Payments received under direct financing leases	10,926			10,926
Equity in earnings of investments in equity investees	(4,539		)	(3,789		)
Cash distributions of earnings of equity investees	10,715			5,917
Non-cash effect of equity-based compensation plans	1,617			(757		)
Deferred and other tax liabilities	(439		)	21
Unrealized gains on derivative transactions	(1,176		)	(15		)
Other, net	343			972
Net changes in components of operating assets and liabilities (Note 11)	19,924			(49,035		)
Net cash provided by operating activities	99,279			9,422
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(80,378		)	(9,328		)
Cash distributions received from equity investees - return of investment	7,309			6,096
Investments in equity investees	(51,431		)	(194		)
Acquisitions	(205,576		)	—
Other, net	(261		)	1,041
Net cash used in investing activities	(330,337		)	(2,385		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	700,700			267,900
Repayments on senior secured credit facility	(665,000		)	(221,900		)
Proceeds from issuance of senior unsecured notes, including premium	101,000			—
Senior unsecured notes issuance costs	(2,690		)	—
Issuance of common units for cash, net	169,421			—
Distributions to common unitholders	(67,445		)	(52,189		)
Other, net	(703		)	(1,176		)
Net cash provided by (used in) financing activities	235,283			(7,365		)
Net increase (decrease) in cash and cash equivalents	4,225			(328		)
Cash and cash equivalents at beginning of period	10,817			5,762
Cash and cash equivalents at end of period	$	15,042		$	5,434

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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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 limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, barges and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We manage our businesses through the following three divisions that constitute our reportable segments:


•	Pipeline transportation of interstate, intrastate and offshore crude oil, and, to a lesser extent, carbon dioxide (or "CO₂");


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


•	Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products and, on a smaller scale, CO₂.

Basis of Presentation and Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries, including Genesis Energy, LLC, our general partner.

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 annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) 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, 2011.

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

2. Acquisition

On January 3, 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility. We account for our interests in Poseidon and Odyssey under the equity method of accounting. We have recorded the assets acquired and liabilities assumed of GOPL in the Unaudited Condensed Consolidated Financial Statements at their estimated fair values on a preliminary basis. Management developed these preliminary fair values.

The preliminary allocation of the purchase price is summarized as follows:



Property and equipment	$	28,456
Equity investees	182,993
Asset retirement obligation assumed	(5,873		)
Total allocation	$	205,576

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana.

Our Unaudited Condensed Consolidated Financial Statements include the results of the acquired pipeline interests since the effective closing date of the acquisition in January 2012. The following table presents selected financial information included in our Unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2012:



	Three Months Ended June 30,		Six Months Ended June 30,
	2012
Revenues	$	1,332	$	3,154
Equity in earnings of equity investees	$	3,041	$	5,697
Net income	$	3,655	$	7,178

The table below presents selected unaudited pro forma financial information for the three and six months ended June 30, 2011 incorporating the historical results of the acquired pipeline interests. The pro forma financial information below has been prepared as if the acquisition had been completed at the beginning of the prior year and is based upon assumptions deemed appropriate by us and may not be indicative of actual results.



	Three Months Ended June 30,		Six Months Ended June 30,
	2011
Pro forma earnings data:
Revenues	$	764,546	$	1,456,100
Equity in earnings of equity investees	$	3,843	$	9,358
Net income	$	19,892	$	28,038
Basic and diluted earnings per unit:
As reported net income per unit	$	0.27	$	0.38
Pro forma net income per unit	$	0.31	$	0.43
As reported units outstanding	64,615		64,615
Pro forma units outstanding	64,615		64,615

3. Inventories

The major components of inventories were as follows:



	June 30, 2012		December 31, 2011
Petroleum products	$	53,962	$	70,769
Crude oil	6,510		11,701
Caustic soda	8,527		11,312
NaHS	3,973		7,337
Other	6		5
Total	$	72,978	$	101,124

Inventories are valued at the lower of cost or market. The costs of inventories exceeded market values by approximately $1.1 million at June 30, 2012, and we reduced the value of inventory in our Unaudited Condensed Consolidated Financial Statements for this difference. At December 31, 2011, market values of our inventories exceeded recorded costs.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Fixed Assets and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following:



	June 30, 2012			December 31, 2011
Pipelines and related assets	$	205,435		$	167,865
Machinery and equipment	47,639			46,233
Transportation equipment	20,051			21,732
Marine vessels	297,400			262,216
Land, buildings and improvements	13,278			13,140
Office equipment, furniture and fixtures	4,397			3,778
Construction in progress	52,044			14,236
Other	11,934			11,938
Fixed assets, at cost	652,178			541,138
Less: Accumulated depreciation	(139,926		)	(124,213		)
Net fixed assets	$	512,252		$	416,925

Our depreciation expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Depreciation expense	$	9,077	$	5,804	$	17,827	$	11,640

Asset Retirement Obligations

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



December 31, 2011	$	5,900
Liabilities incurred and assumed in the current period	5,995
Accretion expense	400
June 30, 2012	$	12,295

We assumed asset retirement obligations of $5.9 million related to pipelines in connection with our acquisition of GOPL. See Note 2 for information related to our acquisitions.

5. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At June 30, 2012 and December 31, 2011, the unamortized excess cost amounts totaled $239.1 million and $97.8 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

The following table presents information included in our Unaudited Condensed Consolidated Financial Statements related to our equity investees.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Genesis’ share of operating earnings	$	3,595		$	1,732		$	9,633		$	6,071
Amortization of excess purchase price	(2,548		)	(1,140		)	(5,094		)	(2,282		)
Net equity in earnings	$	1,047		$	592		$	4,539		$	3,789
Distributions received	$	7,799		$	5,513		$	18,024		$	12,013

The following tables present the combined unaudited balance sheet and income statement information (on a 100% basis) of our equity investees:



	June 30, 2012		December 31, 2011
Balance Sheet Information:
Assets
Current assets	$	66,739	$	12,732
Fixed assets, net	757,389		441,894
Other assets	11,692		18,000
Total assets	$	835,820	$	472,626
Liabilities and equity
Current liabilities	$	52,647	$	5,891
Other liabilities	118,546		8,536
Equity	664,627		458,199
Total liabilities and equity	$	835,820	$	472,626



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Income Statement Information:
Revenues	$	36,452	$	9,835	$	73,970	$	24,844
Operating income	$	14,391	$	2,783	$	33,787	$	11,192
Net income	$	13,682	$	2,783	$	32,357	$	11,202

6. Intangible Assets

The following table summarizes the components of our intangible assets at the dates indicated:



	June 30, 2012						December 31, 2011
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	65,639	$	29,015	$	94,654	$	62,111	$	32,543
Licensing agreements	38,678		21,184		17,494		38,678		19,476		19,202
Supplier relationships	36,469		35,287		1,182		36,469		34,105		2,364
Segment total	169,801		122,110		47,691		169,801		115,692		54,109
Supply & Logistics:
Customer relationships	35,430		24,994		10,436		35,430		23,584		11,846
Intangibles associated with lease	13,260		2,328		10,932		13,260		2,092		11,168
Trade names	18,888		18,888		—		18,888		17,048		1,840
Segment total	67,578		46,210		21,368		67,578		42,724		24,854
Other	18,332		3,866		14,466		17,292		2,899		14,393
Total	$	255,711	$	172,186	$	83,525	$	254,671	$	161,315	$	93,356

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our amortization expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Amortization expense	$	5,355	$	7,473	$	10,870	$	14,646

We estimate that our amortization expense for the next five years will be as follows:



Remainder of 2012	$	9,225
2013	$	14,531
2014	$	12,232
2015	$	10,424
2016	$	8,962

7. Debt

Our obligations under debt arrangements consisted of the following:



	June 30, 2012		December 31, 2011
Senior secured credit facility	$	445,000	$	409,300
7.875% senior unsecured notes (including unamortized premium of $953 and $0 in 2012 and 2011, respectively)	350,953		250,000
Total long-term debt	$	795,953	$	659,300

As of June 30, 2012, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indenture.

Senior Secured Credit Facility

At June 30, 2012, we had $445 million borrowed under our $775 million senior secured credit facility, with $47.4 million of the borrowed amount designated as a loan under the inventory sublimit. The credit facility can be increased up to $1 billion, subject to lender approval. The credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $13.9 million was outstanding at June 30, 2012. 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 under our credit facility at June 30, 2012 was $316.1 million.

In July 2012, we amended and restated our senior secured credit facility. See Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for further details.

Senior Unsecured Notes Issuance

On February 1, 2012, we issued an additional $100 million of aggregate principal amount of senior unsecured notes under our existing 7.875% senior unsecured notes due 2018 indenture. The notes were issued at 101% of face value at an effective interest rate of 7.682%. The notes have the same terms and conditions as the notes previously issued under the indenture. The issuance increased the total aggregate principal amount under the indenture to $350 million. The net proceeds were used to repay borrowings under our credit facility.

8. Partners’ Capital and Distributions

On March 28, 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. At June 30, 2012, our outstanding common units consisted of 79,424,522 Class A units and 39,997 Class B units.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Waiver Units

Our waiver units are non-voting securities entitled to a minimal preferential quarterly distribution. At issuance our waiver units were comprised of four classes (designated Class 1, Class 2, Class 3 and Class 4) of 1,750,000 authorized units each, of which 1,738,000 units of each class have been issued. The waiver units in each class are convertible into Class A common units in the calendar quarter at a 1:1 conversion rate during which each of our common units receives a specified minimum quarterly distribution and our distribution coverage ratio (after giving effect to the then convertible waiver units) would be at least 1.1 times. The minimum distribution per common unit required for conversion is $0.43 (Class 1), $0.46 (Class 2), $0.49 (Class 3) and $0.52 (Class 4). On February 14, 2012, our Class 1 waiver units became convertible as we paid a distribution of $0.44 per common unit and satisfied the conversion coverage ratio requirement. All Class 1 waiver units were converted into common units by March 31, 2012. At June 30, 2012, we had 5,214,099 waiver units outstanding comprised of the last three classes.

On August 14, 2012, each of our Class 2 waiver units will become convertible (at the option of the holder thereof) as we will pay a distribution of $0.46 per common unit and satisfy the conversion coverage ratio requirement. The waiver units convert into common units no later than six months from the date they become convertible.

Distributions

We paid or will pay the following distributions in 2011 and 2012:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2011
1^st Quarter	May 13, 2011		$	0.4075	$	26,343
2^nd Quarter	August 12, 2011		$	0.4150	$	29,878
3^rd Quarter	November 14, 2011		$	0.4275	$	30,777
4^th Quarter	February 14, 2012		$	0.4400	$	31,677
2012
1^st Quarter	May 15, 2012		$	0.4500	$	35,759
2^nd Quarter	August 14, 2012	⁽¹⁾	$	0.4600	$	36,554

(1) This distribution will be paid to unitholders of record as of August 1, 2012.

9. Business Segment Information

Our operations consist of three operating segments:


(1)	Pipeline Transportation – interstate, intrastate and offshore crude oil, and to a lesser extent, CO₂;


(2)	Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product, NaHS and;


(3)	Supply and Logistics – terminaling, blending, storing, marketing, and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and, on a smaller scale, CO₂.

Substantially all of our revenues are derived from, and substantially all of our assets are located in the United States.

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 capital investment.

Segment information for the periods presented below was as follows:

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	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended June 30, 2012
Segment margin (a)	$	20,785	$	17,278		$	24,768		$	62,831
Capital expenditures (b)	$	31,901	$	360		$	22,173		$	54,434
Revenues:
External customers	$	13,398	$	50,575		$	858,695		$	922,668
Intersegment (c)	3,823		(2,255		)	(1,568		)	—
Total revenues of reportable segments	$	17,221	$	48,320		$	857,127		$	922,668
Three Months Ended June 30, 2011
Segment margin (a)	$	16,927	$	18,947		$	11,799		$	47,673
Capital expenditures (b)	$	1,234	$	189		$	1,819		$	3,242
Revenues:
External customers	$	12,051	$	51,334		$	699,405		$	762,790
Intersegment (c)	3,033		(1,971		)	(1,062		)	—
Total revenues of reportable segments	$	15,084	$	49,363		$	698,343		$	762,790
Six Months Ended June 30, 2012
Segment margin (a)	$	46,132	$	34,527		$	42,424		$	123,083
Capital expenditures (b)	$	278,329	$	1,270		$	63,004		$	342,603
Revenues:
External customers	$	28,374	$	100,948		$	1,726,289		$	1,855,611
Intersegment (c)	8,256		(4,583		)	(3,673		)	—
Total revenues of reportable segments	$	36,630	$	96,365		$	1,722,616		$	1,855,611
Six Months Ended June 30, 2011
Segment margin (a)	$	34,609	$	36,895		$	25,324		$	96,828
Capital expenditures (b)	$	1,682	$	469		$	2,127		$	4,278
Revenues:
External customers	$	24,644	$	100,917		$	1,327,027		$	1,452,588
Intersegment (c)	4,895		(4,008		)	(887		)	—
Total revenues of reportable segments	$	29,539	$	96,909		$	1,326,140		$	1,452,588

Total assets by reportable segment were as follows:



	June 30, 2012		December 31, 2011
Pipeline transportation	$	856,418	$	594,728
Refinery services	418,050		426,993
Supply and logistics	674,834		659,576
Other assets	51,048		49,547
Total consolidated assets	$	2,000,350	$	1,730,844


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

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	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Segment Margin	$	62,831		$	47,673		$	123,083		$	96,828
Corporate general and administrative expenses	(8,707		)	(7,689		)	(17,328		)	(15,073		)
Depreciation and amortization	(15,357		)	(14,253		)	(30,392		)	(28,156		)
Net loss on disposal of surplus assets	(473		)	(249		)	(217		)	(238		)
Interest expense	(10,228		)	(9,011		)	(20,824		)	(17,710		)
Distributable cash from equity investees in excess of equity in earnings	(6,752		)	(4,921		)	(13,485		)	(8,224		)
Non-cash items not included in segment margin	(1,577		)	7,103			(253		)	(331		)
Cash payments from direct financing leases in excess of earnings	(1,249		)	(1,141		)	(2,470		)	(2,254		)
Income before income taxes	$	18,488		$	17,512		$	38,114		$	24,842

(b)

Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of internal growth projects) as well as acquisitions of businesses and interests in equity investees. See Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for more information regarding our capital expenditures. Capital spending in our pipeline transportation segment included $17.9 million and $51.4 million during the three and six months ended June 30, 2012, respectively, representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline. For the six months ended June 30, 2012, capital spending in our pipeline transportation segment also included $205.6 million for the acquisition of interests in several Gulf of Mexico pipelines and pipeline equity investees. For the six months ended June 30, 2012, capital spending in our supply and logistics segment also included $30.6 million for the purchase of barge assets.


(c)	Intersegment sales were conducted under terms no more or less favorable than then-existing market conditions.

10. Transactions with Related Parties

Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Revenues:
Petroleum products sales to an affiliate of the Robertson Group ⁽¹⁾	$	4,578	$	11,533	$	14,766	$	21,254
Sales of CO₂ to Sandhill Group, LLC ⁽²⁾	660		432		1,273		975
Petroleum products sales to Davison family businesses ⁽¹⁾	374		245		686		487
Costs and expenses:
Marine operating fuel and expenses provided by an affiliate of the Robertson Group ⁽¹⁾	2,244		780		4,201		1,820
Amounts paid to our CEO in connection with the use of his aircraft	150		—		300		—


(1)	The Robertson Group owned 9% of our Class A common units and 74% of our Class B common units at June 30, 2012. The Davison family owned 15% of our Class A common units at June 30, 2012.


(2)	We own a 50% interest in Sandhill Group, LLC.

Amounts due to and from Related Parties

At June 30, 2012 and December 31, 2011, an affiliate of the Robertson Group owed us $0.2 million and $1.9 million, respectively, for petroleum product sales. We owed the affiliate $0.2 million and $0.1 million, respectively, for marine related costs. Sandhill Group, LLC owed us $0.4 million and $0.2 million, at June 30, 2012 and December 31, 2011, respectively, for purchases of CO₂.

11. Supplemental Cash Flow Information

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

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	Six Months Ended June 30,
	2012			2011
(Increase) decrease in:
Accounts receivable	$	6,698		$	(54,810	)
Inventories	28,146			(33,847		)
Other current assets	5,197			(1,727		)
Increase (decrease) in:
Accounts payable	(9,549		)	37,167
Accrued liabilities	(10,568		)	4,182
Net changes in components of operating assets and liabilities	$	19,924		$	(49,035	)

Payments of interest and commitment fees were $21.6 million and $17.6 million for the six months ended June 30, 2012 and 2011, respectively. At June 30, 2012 and 2011, we had incurred liabilities for fixed and intangible asset additions totaling $8.1 million and $0.9 million, respectively, that had not been paid at the end of the second quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

12. Derivatives

Commodity Derivatives

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

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

At June 30, 2012, we had the following outstanding derivative commodity futures and options contracts that were entered into to economically hedge inventory or fixed price purchase commitments. We had no outstanding derivative contracts that were designated as hedges under accounting rules.

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	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	157		81
Weighted average contract price per bbl	$	89.58	$	90.88
Heating oil futures:
Contract volumes (1,000 bbls)	25		—
Weighted average contract price per gal	$	2.56	$	—
RBOB gasoline futures:
Contract volumes (1,000 bbls)	12		—
Weighted average contract price per gal	$	2.49	$	—
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	555		145
Weighted average contract price per bbl	$	87.00	$	88.15
Crude oil options:
Contract volumes (1,000 bbls)	285		70
Weighted average premium received	$	2.04	$	1.12

Financial Statement Impacts

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

The following tables reflect the estimated fair value gain (loss) position of our derivatives at June 30, 2012 and December 31, 2011:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	June 30, 2012				December 31, 2011
Asset Derivatives:
Commodity derivatives - futures and call options:
Undesignated hedges	Current Assets - Other	$	695			$	306
Total asset derivatives		$	695			$	306
Liability Derivatives:
Commodity derivatives - futures and call options:
Undesignated hedges	Current Assets - Other	$	(2,032	)	⁽¹⁾	$	(2,820	)	⁽¹⁾
Total liability derivatives		$	(2,032	)		$	(2,820	)

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

Effect on Operating Results

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	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended June 30,					Six Months Ended June 30,
		2012		2011			2012		2011
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	—	$	(173	)	$	—	$	(434	)
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	13,569		(13,637		)	2,858		(31,890		)
Total commodity derivatives		$	13,569	$	(13,810	)	$	2,858	$	(32,324	)

13. Fair-Value Measurements

We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value:


(1)	Level 1 fair values are based on observable inputs such as quoted prices in active markets;


(2)	Level 2 fair values are based on pricing inputs other than quoted prices in active markets and are either directly or indirectly observable as of the measurement date; and


(3)	Level 3 fair values are based on unobservable inputs in which little or no market data exists. 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.

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 at the dates indicated.



	Fair Value at							Fair Value at
	June 30, 2012							December 31, 2011
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	695		$	—	$	—	$	306		$	—	$	—
Liabilities	$	(2,032	)	$	—	$	—	$	(2,820	)	$	—	$	—

Our commodity derivatives include exchange-traded futures and exchange-traded options 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.

See Note 12 for additional information on our derivative instruments.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that were were required to measure and record such assets within our Unaudited Condensed Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3.

We utilize fair value on a recurring basis to measure our contingent consideration that is a result of certain acquisitions. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified in Level 3.

Other Fair Value Measurements

We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

approximates current market rates for similar instruments with comparable maturities. At June 30, 2012, our senior unsecured notes had a carrying value of $351 million and a fair value of $348.3 million, compared to $250 million and $253.1 million, respectively, at December 31, 2011. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.

14. 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.

15. Condensed Consolidating Financial Information

Our $350 million aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. Each subsidiary guarantor and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P. See Note 7 for additional information regarding our consolidated debt obligations. The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

June 30, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	2	$	—	$	14,653		$	387		$	—		$	15,042
Other current assets	712,588		—		306,465			32,011			(724,383		)	326,681
Total current assets	712,590		—		321,118			32,398			(724,383		)	341,723
Fixed assets, at cost	—		—		553,860			98,318			—			652,178
Less: Accumulated depreciation	—		—		(128,585		)	(11,341		)	—			(139,926		)
Net fixed assets	—		—		425,275			86,977			—			512,252
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	15,633		—		263,517			160,069			(165,786		)	273,433
Equity investees	—		—		547,896			—			—			547,896
Investments in subsidiaries	1,003,161		—		98,668			—			(1,101,829		)	—
Total assets	$	1,731,384	$	—	$	1,981,520		$	279,444		$	(1,991,998	)	$	2,000,350
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,129	$	—	$	944,407		$	13,787		$	(724,542	)	$	235,781
Senior secured credit facility	445,000		—		—			—			—			445,000
Senior unsecured notes	350,953		—		—			—			—			350,953
Deferred tax liabilities	—		—		12,110			—			—			12,110
Other liabilities	—		—		21,042			167,763			(165,601		)	23,204
Total liabilities	798,082		—		977,559			181,550			(890,143		)	1,067,048
Partners’ capital	933,302		—		1,003,961			97,894			(1,101,855		)	933,302
Total liabilities and partners’ capital	$	1,731,384	$	—	$	1,981,520		$	279,444		$	(1,991,998	)	$	2,000,350

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	3	$	—	$	9,182		$	1,632		$	—		$	10,817
Other current assets	597,966		—		341,131			31,897			(605,707		)	365,287
Total current assets	597,969		—		350,313			33,529			(605,707		)	376,104
Fixed assets, at cost	—		—		444,262			96,876			—			541,138
Less: Accumulated depreciation	—		—		(114,655		)	(9,558		)	—			(124,213		)
Net fixed assets	—		—		329,607			87,318			—			416,925
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	14,773		—		276,450			162,373			(167,774		)	285,822
Equity investees	—		—		326,947			—			—			326,947
Investments in subsidiaries	841,725		—		96,303			—			(938,028		)	—
Total assets	$	1,454,467	$	—	$	1,704,666		$	283,220		$	(1,711,509	)	$	1,730,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,529	$	—	$	835,013		$	17,562		$	(605,676	)	$	249,428
Senior secured credit facility	409,300		—		—			—			—			409,300
Senior unsecured notes	250,000		—		—			—			—			250,000
Deferred tax liabilities	—		—		12,549			—			—			12,549
Other liabilities	—		—		14,673			169,842			(167,586		)	16,929
Total liabilities	661,829		—		862,235			187,404			(773,262		)	938,206
Partners’ capital	792,638		—		842,431			95,816			(938,247		)	792,638
Total liabilities and partners’ capital	$	1,454,467	$	—	$	1,704,666		$	283,220		$	(1,711,509	)	$	1,730,844

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	849,469	$	32,159		$	(24,501	)	$	857,127
Refinery services	—			—		45,311		6,744			(3,735		)	48,320
Pipeline transportation services	—			—		10,869		6,352			—			17,221
Total revenues	—			—		905,649		45,255			(28,236		)	922,668
COSTS AND EXPENSES:
Supply and logistics costs	—			—		829,597		28,022			(24,499		)	833,120
Refinery services operating costs	—			—		29,175		6,087			(4,212		)	31,050
Pipeline transportation operating costs	—			—		4,856		176			—			5,032
General and administrative	—			—		9,937		30			—			9,967
Depreciation and amortization	—			—		14,459		898			—			15,357
Net loss on disposal of surplus assets	—			—		473		—			—			473
Total costs and expenses	—			—		888,497		35,213			(28,711		)	894,999
OPERATING INCOME	—			—		17,152		10,042			475			27,669
Equity in earnings of subsidiaries	28,791			—		5,809		—			(34,600		)	—
Equity in earnings of equity investees	—			—		1,047		—			—			1,047
Interest (expense) income, net	(10,207		)	—		4,141		(4,162		)	—			(10,228		)
Income before income taxes	18,584			—		28,149		5,880			(34,125		)	18,488
Income tax benefit (expense)	—			—		216		(120		)	—			96
NET INCOME	$	18,584		$	—	$	28,365	$	5,760		$	(34,125	)	$	18,584

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2011



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	698,343	$	—		$	—		$	698,343
Refinery services	—			—		46,782		4,668			(2,087		)	49,363
Pipeline transportation services	—			—		8,983		6,101			—			15,084
Total revenues	—			—		754,108		10,769			(2,087		)	762,790
COSTS AND EXPENSES:
Supply and logistics costs	—			—		679,357		—			—			679,357
Refinery services operating costs	—			—		28,675		4,004			(2,415		)	30,264
Pipeline transportation operating costs	—			—		4,210		146			—			4,356
General and administrative	—			—		8,380		—			—			8,380
Depreciation and amortization	—			—		13,604		649			—			14,253
Net loss on disposal of surplus assets	—			—		249		—			—			249
Total costs and expenses	—			—		734,475		4,799			(2,415		)	736,859
OPERATING INCOME	—			—		19,633		5,970			328			25,931
Equity in earnings of subsidiaries	26,352			—		1,577		—			(27,929		)	—
Equity in earnings of equity investees	—			—		592		—			—			592
Interest (expense) income, net	(8,994		)	—		4,241		(4,258		)	—			(9,011		)
Income before income taxes	17,358			—		26,043		1,712			(27,601		)	17,512
Income tax benefit (expense)	—			—		30		(184		)	—			(154		)
NET INCOME	$	17,358		$	—	$	26,073	$	1,528		$	(27,601	)	$	17,358

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	1,709,376	$	64,338		$	(51,098	)	$	1,722,616
Refinery services	—			—		93,907		9,389			(6,931		)	96,365
Pipeline transportation services	—			—		23,785		12,845			—			36,630
Total revenues	—			—		1,827,068		86,572			(58,029		)	1,855,611
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,673,465		56,762			(51,096		)	1,679,131
Refinery services operating costs	—			—		59,816		9,136			(7,123		)	61,829
Pipeline transportation operating costs	—			—		9,690		394			—			10,084
General and administrative	—			—		19,499		60			—			19,559
Depreciation and amortization	—			—		28,602		1,790			—			30,392
Net loss on disposal of surplus assets	—			—		217		—			—			217
Total costs and expenses	—			—		1,791,289		68,142			(58,219		)	1,801,212
OPERATING INCOME	—			—		35,779		18,430			190			54,399
Equity in earnings of subsidiaries	58,959			—		10,131		—			(69,090		)	—
Equity in earnings of equity investees				—		4,539		—						4,539
Interest (expense) income, net	(20,771		)	—		8,295		(8,348		)	—			(20,824		)
Income before income taxes	38,188			—		58,744		10,082			(68,900		)	38,114
Income tax benefit (expense)	—			—		121		(47		)	—			74
NET INCOME	$	38,188		$	—	$	58,865	$	10,035		$	(68,900	)	$	38,188

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	1,326,140		$	—		$	—		$	1,326,140
Refinery services	—			—		94,292			9,148			(6,531		)	96,909
Pipeline transportation services	—			—		16,904			12,635			—			29,539
Total revenues	—			—		1,437,336			21,783			(6,531		)	1,452,588
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,300,721			—			—			1,300,721
Refinery services operating costs	—			—		58,193			8,224			(6,567		)	59,850
Pipeline transportation operating costs	—			—		8,119			307			—			8,426
General and administrative	—			—		16,434			—			—			16,434
Depreciation and amortization	—			—		26,858			1,298			—			28,156
Net loss on disposal of surplus assets	—			—		238			—			—			238
Total costs and expenses	—			—		1,410,563			9,829			(6,567		)	1,413,825
OPERATING INCOME	—			—		26,773			11,954			36			38,763
Equity in earnings of subsidiaries	42,060			—		3,293			—			(45,353		)	—
Equity in earnings of equity investees	—			—		3,789			—			—			3,789
Interest (expense) income, net	(17,672		)	—		8,500			(8,538		)	—			(17,710		)
Income before income taxes	24,388			—		42,355			3,416			(45,317		)	24,842
Income tax expense	—			—		(234		)	(220		)	—			(454		)
NET INCOME	$	24,388		$	—	$	42,121		$	3,196		$	(45,317	)	$	24,388

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash (used in) provided by operating activities	$	(86,721	)	$	—	$	231,807		$	10,216		$	(56,023	)	$	99,279
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(78,937		)	(1,441		)	—			(80,378		)
Cash distributions received from equity investees - return of investment	20,155			—		7,309			—			(20,155		)	7,309
Investments in equity investees	(169,421		)	—		(52,226		)	—			170,216			(51,431		)
Acquisitions	—			—		(205,576		)	—			—			(205,576		)
Repayments on loan to non-guarantor subsidiary	—			—		1,987			—			(1,987		)	—
Other, net	—			—		534			(795		)	—			(261		)
Net cash used in by investing activities	(149,266		)	—		(326,909		)	(2,236		)	148,074			(330,337		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	700,700			—		—			—			—			700,700
Repayments on senior secured credit facility	(665,000		)	—		—			—			—			(665,000		)
Proceeds from issuance of senior unsecured notes, including premium	101,000			—		—			—			—			101,000
Senior unsecured notes issuance costs	(2,690		)	—		—			—			—			(2,690		)
Issuance of ownership interests to partners for cash	169,421			—		169,421			795			(170,216		)	169,421
Distributions to partners/owners	(67,445		)	—		(67,445		)	(8,750		)	76,195			(67,445		)
Other, net	—			—		(1,403		)	(1,270		)	1,970			(703		)
Net cash provided by (used in) financing activities	235,986			—		100,573			(9,225		)	(92,051		)	235,283
Net (decrease) increase in cash and cash equivalents	(1		)	—		5,471			(1,245		)	—			4,225
Cash and cash equivalents at beginning of period	3			—		9,182			1,632			—			10,817
Cash and cash equivalents at end of period	$	2		$	—	$	14,653		$	387		$	—		$	15,042

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2011



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash (used in) provided by operating activities	$	(45,998	)	$	—	$	53,434		$	1,971		$	15		$	9,422
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(9,328		)	—			—			(9,328		)
Cash distributions received from equity investees - return of investment	52,189			—		6,096			—			(52,189		)	6,096
Investments in equity investees	—			—		(194		)	—			—			(194		)
Repayments on loan to non-guarantor subsidiary	—			—		1,796			—			(1,796		)	—
Other, net	—			—		1,041			—			—			1,041
Net cash provided by (used in) investing activities	52,189			—		(589		)	—			(53,985		)	(2,385		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	267,900			—		—			—			—			267,900
Repayments on senior secured credit facility	(221,900		)	—		—			—			—			(221,900		)
Distributions to partners/owners	(52,189		)	—		(52,189		)	—			52,189			(52,189		)
Other, net	—			—		(1,176		)	(1,781		)	1,781			(1,176		)
Net cash used in financing activities	(6,189		)	—		(53,365		)	(1,781		)	53,970			(7,365		)
Net increase (decrease) in cash and cash equivalents	2			—		(520		)	190			—			(328		)
Cash and cash equivalents at beginning of period	1			—		5,082			679			—			5,762
Cash and cash equivalents at end of period	$	3		$	—	$	4,562		$	869		$	—		$	5,434

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

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this quarterly report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K.

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


•	Overview


•	Acquisition


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income of $18.6 million, or $0.23 per common unit during the three months ended June 30, 2012 (“2012 Quarter”) compared to net income of $17.4 million or $0.27 per common unit during the three months ended June 30, 2011 (“2011 Quarter”). The significant factors affecting net income were improved operating results by two of our business segments partially offset by increases in general and administrative expense, depreciation and amortization expense and interest costs. A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.

Segment Margin (as described below in “Financial Measures”) increased by $15.2 million, or 32%, in the 2012 Quarter, as compared to the 2011 Quarter. This increase resulted from improvement in Segment Margin in our pipeline transportation and supply and logistics segments of 23% and 110%, respectively, partially offset by a 9% decrease in our refinery services segment. The contribution from our recently acquired interests in certain Gulf of Mexico pipelines and higher crude oil tariff revenues were the primary factors increasing pipeline transportation Segment Margin. Results for our pipeline transportation segment were somewhat reduced due to ongoing maintenance at several dedicated fields that significantly reduced throughput on one of our major offshore pipelines, however we expect this maintenance to be completed in the third quarter of 2012. Our refinery services Segment Margin decreased primarily as a result of increased costs due to longer than anticipated refinery turnarounds at some of our largest refinery service locations. To ensure uninterrupted supplies to our customers, we incurred increased costs as a result of processing at less efficient locations. Our supply and logistics segment benefited from acquisitions and other growth initiatives completed in the second half of 2011 as well as higher volumes due to increased industry activity in our operational areas.

Available Cash before Reserves increased $11.3 million, or 35%, in the 2012 Quarter to $43.2 million consistent with the increase in net income described above. See “Financial Measures” below for additional information on Available Cash before Reserves.

Distribution Increase

In July 2012, we declared our twenty-eighth consecutive increase in our quarterly distribution to our common unitholders relative to the second quarter of 2012. During this period, twenty-three of those quarterly increases have been 10% or greater year-over-year. In August 2012, we will pay a distribution of $0.46 per unit representing a 10.8% increase from our distribution of $0.4150 per unit related to the second quarter of 2011. During the second quarter of 2012, we paid a distribution of $0.45 per unit related to the first quarter of 2012.

Acquisition

In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility.

This acquisition complements our existing infrastructure in the Gulf of Mexico and enhances our ability to provide capacity and market optionality to producers for their existing and future developments as well as our refining customers

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onshore Texas and Louisiana. The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of Enterprise Products serves as the operator of Poseidon. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco, ConocoPhillips and Shell. An affiliate of Shell serves as the operator of Eugene Island. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey, and an affiliate of Shell serves as the operator of Odyssey.

Financial Measures

In the discussions that follow, we will focus on our revenues, expenses and net income, as well as 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.

Segment Margin

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 capital investment. A reconciliation of Segment Margin to income before income taxes is included in our segment disclosures in Note 9 to our Unaudited Condensed Consolidated Financial Statements.

Available Cash before Reserves

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 below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts, and other market participants.

Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some 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.

Available Cash before Reserves is a performance 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 is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

Available Cash before Reserves is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation and amortization), 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

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hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, 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.

Available Cash before Reserves for the periods presented below was as follows:



	Three Months Ended June 30,
	2012			2011
	(in thousands)
Net income	$	18,584		$	17,358
Depreciation and amortization	15,357			14,253
Cash received from direct financing leases not included in income	1,249			1,141
Cash effects of sales of certain assets	767			1,413
Effects of distributable cash generated by equity method investees not included in income	6,752			4,921
Cash effects of equity-based compensation plans	(477		)	(716		)
Non-cash equity-based compensation expense (benefit)	1,013			(270		)
Expenses related to acquiring or constructing assets that provide new sources of cash flow	180			1,466
Unrealized loss (gain) on derivative transactions excluding fair value hedges	816			(6,968		)
Maintenance capital expenditures	(806		)	(610		)
Non-cash tax benefit	(402		)	(124		)
Other items, net	181			80
Available Cash before Reserves	$	43,214		$	31,944

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2012 Quarter increased $159.9 million, or 21% from the 2011 Quarter. Additionally, our costs and expenses increased $158.1 million, or 21% between the two periods.

Our revenues for the six months ended June 30, 2012 increased $403 million, or 28% from the six months ended June 30, 2011. Costs and expenses increased $387.4 million, or 27% between the two six month 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 and six month periods is primarily attributable to increased volumes from our continuing operations and our acquisitions, partially offset by decreases in the market prices for crude oil and petroleum products as described below.

Volumes increased in our supply and logistics segment by 30% quarter to quarter and 26% between the six month periods as explained in our supply and logistics Segment Margin discussion below. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") decreased 9% to $93.49 per barrel in the second quarter of 2012, as compared to $102.56 per barrel in the second quarter of 2011. Average closing prices for WTI crude oil on the NYMEX were consistent between the six month periods at approximately $98 per barrel.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2012 and 2011 was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Pipeline transportation	$	20,785	$	16,927	$	46,132	$	34,609
Refinery services	17,278		18,947		34,527		36,895
Supply and logistics	24,768		11,799		42,424		25,324
Total Segment Margin	$	62,831	$	47,673	$	123,083	$	96,828

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Pipeline Transportation Segment

Operating results and volumetric data for our pipeline transportation segment are presented below.



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	7,312		$	5,867		$	14,103		$	11,200
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees	7,573			4,518			18,187			10,038
CO₂ tariffs and revenues from direct financing leases of CO₂ pipelines	6,447			6,212			13,038			12,858
Sales of crude oil pipeline loss allowance volumes	1,530			2,109			4,783			3,628
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(3,554		)	(3,180		)	(6,923		)	(5,771		)
Payments received under direct financing leases not included in income	1,249			1,141			2,470			2,254
Other	228			260			474			402
Segment Margin	$	20,785		$	16,927		$	46,132		$	34,609

Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Jay	18,100			16,655			18,460			15,803
Texas	53,653			47,091			49,094			46,971
Mississippi	18,930			21,133			18,597			20,883
Offshore crude oil pipelines:
CHOPS⁽¹⁾	43,407			108,964			72,468			139,666
Poseidon ^{(1) (2)}	214,470			—			202,108			—
Odyssey ^{(1) (2)}	36,091			—			38,080			—
GOPL ⁽²⁾	18,125			—			21,367			—
CO₂ pipeline (Mcf/day):
Free State	166,289			131,683			172,150			153,220

(1) Volumes for our equity method investees are presented on a 100% basis.

(2) Acquired in January 2012.

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011

Pipeline transportation Segment Margin for the 2012 Quarter increased $3.9 million, or 23%. The significant components of this change were as follows:


•	Crude oil tariff revenues of onshore crude oil pipelines increased $1.4 million primarily due to upward tariff indexing for our FERC regulated pipelines effective in July 2011.

•

Segment Margin from our offshore crude oil pipelines increased $3.1 million reflecting a $7 million contribution from our recently acquired interests in the Gulf of Mexico pipelines. The increase was partially offset by lower volumes transported on CHOPS of approximately 66,000 barrels per day as a result of ongoing improvements by producers at the connected production fields, however we expect this maintenance to be completed in the third quarter of 2012. The contribution to Segment Margin by CHOPS declined by $3.9 million from the 2011 Quarter.

Six Months Ended June 30, 2012 Compared with Six Months Ended June 30, 2011.

Segment Margin for our pipeline transportation segment increased $11.5 million, or 33%, between the six month periods. The significant components of this change were as follows:

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•	Crude oil tariff revenues of onshore crude oil pipelines increased $2.9 million primarily due to upward tariff indexing for our FERC regulated pipelines effective in July 2011.

•

Segment Margin from our offshore crude oil pipelines increased $8.1 million reflecting a $14.5 million contribution from our recently acquired interests in the Gulf of Mexico pipelines. The increase was partially offset by lower volumes transported on CHOPS of approximately 67,000 barrels per day as a result of ongoing improvements by producers at the connected production fields, however we expect this maintenance to be completed in the third quarter of 2012. The contribution to Segment Margin by CHOPS declined by $6.4 million as compared to the first six months of 2011.


•	Revenues from sales of pipeline loss allowance volumes improved Segment Margin by $1.2 million due to an increase of approximately 7,000 barrels sold in the first half of 2012 compared to the first half of 2011.


•	Onshore pipeline operating costs, excluding non-cash charges, increased $1.2 million due to increased variable operating costs and employee compensation and related benefit costs, and remained relatively constant on a per barrel basis during each of those periods.

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Volumes sold (in Dry short tons "DST"):
NaHS volumes	39,184			36,080			72,949			73,313
NaOH (caustic soda) volumes	14,670			26,209			35,588			50,849
Total	53,854			62,289			108,537			124,162

Revenues (in thousands):
NaHS revenues	$	40,239		$	36,459		$	77,034		$	73,258
NaOH (caustic soda) revenues	8,447			12,004			20,275			22,243
Other revenues	1,889			2,871			3,639			5,416
Total external segment revenues	$	50,575		$	51,334		$	100,948		$	100,917

Segment Margin (in thousands)	$	17,278		$	18,947		$	34,527		$	36,895

Average index price for NaOH per DST ⁽¹⁾	$	548		$	495		$	559		$	468
Raw material and processing costs as % of segment revenues	51		%	41		%	49		%	42		%

(1) Source: Harriman Chemsult Ltd.

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011

Refinery services Segment Margin for the 2012 Quarter decreased $1.7 million, or 9%. The significant components of this fluctuation were as follows:


•	NaHS sales volumes increased 9% between the quarterly periods primarily due to higher sales to South American customers in the 2012 Quarter. Sales volumes between quarters to customers in South America can fluctuate due to timing of deliveries.

•

NaHS revenues increased primarily as a function of the increase in the average index price for caustic soda and increased sales volumes. 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. In addition, in the second quarter of 2012, longer than anticipated refinery

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turnarounds at some of our largest refinery service locations resulted in increased costs as a result of processing at less efficient locations to ensure uninterrupted supplies to our customers.

•

Caustic soda sales volumes decreased 44% primarily due to turnarounds at some of our refinery customers. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. 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.

•

Average index prices for caustic soda increased to $548 per DST in the second quarter of 2012 compared to $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, generally changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually 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, 2012 Compared with Six Months Ended June 30, 2011

Refinery services Segment Margin decreased $2.4 million, or 6%, between the six month periods. The significant components of this fluctuation were as follows:


•	NaHS 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. In addition, in the first half of 2012, longer than anticipated refinery turnarounds at some of our largest refinery service locations resulted in increased costs as a result of processing at less efficient locations to ensure uninterrupted supplies to our customers.

•

Caustic soda sales volumes decreased 30% primarily due to turnarounds at some of our refinery customers. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. 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.

•

Average index prices for caustic soda increased to $559 per DST in the first half of 2012 compared to $468 per DST during the first half 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, generally changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually 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.

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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,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Supply and logistics revenue	$	857,127		$	698,343		$	1,722,616		$	1,326,140
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(791,597		)	(660,512		)	(1,601,684		)	(1,250,977		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(40,289		)	(26,544		)	(77,919		)	(50,851		)
Other	(473		)	512			(589		)	1,012
Segment Margin	$	24,768		$	11,799		$	42,424		$	25,324

Volumes of crude oil and petroleum products (barrels per day)	90,211			69,546			87,069			69,020

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011

The average market prices of crude oil and petroleum products decreased by more than $9 per barrel, or 9%, between the two quarterly periods; however that price volatility has a limited impact on our Segment Margin. Segment Margin for our supply and logistics segment increased by $13 million, or 110%, during the 2012 Quarter.

The increase in Segment Margin during the 2012 Quarter resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking and barge fleets. We were able to increase volumes by 30% quarter-over-quarter as a result of increased volumes in our Alabama and Florida regions as well as increased industry activity in the Eagle Ford Shale and Niobrara Shale.

Six Months Ended June 30, 2012 Compared with Six Months Ended June 30, 2011

Segment Margin for our supply and logistics segment increased $17.1 million, or 68%, between the six month periods. Average market prices of crude oil and petroleum products were consistent at approximately $98 per barrel between the first half of 2011 and first half of 2012, however, as previously discussed, price volatility has a limited impact on our Segment Margin.

The increase in Segment Margin during the first six months of 2012 resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking and barge fleets. The volumes we handled during the first six months of 2012 increased by 26% as a result of increased volumes in our Alabama and Florida regions as well as increased industry activity in the Eagle Ford Shale and Niobrara Shale.

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	5,753	$	4,464	$	11,154	$	8,927
Segment	2,870		2,214		5,106		4,342
Equity-based compensation plan expense	1,164		236		2,511		644
Third party costs related to business development activities and growth projects	180		1,466		788		2,521
Total general and administrative expenses	$	9,967	$	8,380	$	19,559	$	16,434

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Routine corporate and segment general and administrative expenses increased between the three and six month periods as a result of salary and benefits expenses associated with increases in personnel to support our growth. Additionally, increases in the market price of our common units affected expense related to our equity-based compensation plans. A decrease in third party costs related to business and growth transactions resulted in a decrease of approximately $1.3 million and $1.7 million, for the three and six month periods, respectively.

Depreciation and amortization expense



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Depreciation expense	$	9,077	$	5,804	$	17,827	$	11,640
Amortization of intangible assets	5,355		7,473		10,870		14,646
Amortization of CO2 volumetric production payments	925		976		1,695		1,870
Total depreciation and amortization expense	$	15,357	$	14,253	$	30,392	$	28,156

Total depreciation and amortization expense increased $1.1 million and $2.2 million, between the quarterly and six month periods, respectively, primarily as a result of our recent acquisitions, including the black oil barge transportation assets in August 2011. The increase in total depreciation and amortization was partially offset by lower amortization of intangible assets. We amortize our intangible assets over the period which we expect them to contribute to our future cash flows. Generally, the amortization we record on those assets is greater in the initial years following their acquisition because our intangible assets are generally more valuable in the first years after an acquisition.

Interest expense, net



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	3,236		$	3,383		$	7,346		$	6,509
Interest expense, senior unsecured notes	6,862			4,976			12,750			9,898
Amortization of debt issuance costs	931			655			1,830			1,310
Capitalized interest	(790		)	—			(1,090		)	—
Interest income	(11		)	(3		)	(12		)	(7		)
Net interest expense	$	10,228		$	9,011		$	20,824		$	17,710

Net interest expense increased $1.2 million between the quarterly periods and $3.1 million between the six month periods primarily as a result of increased borrowings associated with acquisitions. Interest expense on our senior unsecured notes increased $1.9 million and $2.9 million over the same periods as a result of issuing an additional $100 million of notes under the indenture in February 2012 to repay borrowings under our credit facility. Capitalized interest costs of $0.8 million and $1.1 million in the three and six month periods, respectively, attributable primarily to our investments in the SEKCO pipeline joint venture (see below for more information) partially offset the increase in interest expense.

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.

Other

Net income for the three months ended June 30, 2012 included an unrealized loss on derivative positions of $0.8 million. Net income for the same period in 2011 included an unrealized gain on derivative positions of $7 million. Net income for the six months ended June 30, 2012 and 2011 included an unrealized gain on derivative positions of $1.2 million and

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$0.3 million, respectively. Those amounts are included in Supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations and are not a component of Segment Margin.

Liquidity and Capital Resources

General

As of June 30, 2012, we had $316.1 million of borrowing capacity available under our $775 million senior secured revolving credit facility; for which we increased the commitments to $1 billion in July 2012 (as discussed below). We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations and borrowing availability under our credit facility.

Our primary cash requirements consist of:


•	Working capital, primarily inventories;


•	Routine operating expenses;


•	Capital expansion and maintenance projects;


•	Acquisitions of assets or businesses;


•	Interest payments related to outstanding debt; and


•	Quarterly cash distributions to our unitholders.

We continue to pursue a growth strategy that requires significant capital. In January 2012, we borrowed $205.6 million under our credit facility to acquire interests in several pipeline systems. See “Capital Expenditures and Business and Asset Acquisitions” below for more information related to our capital spending and acquisitions.

Capital Resources

Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time — including through equity and debt offerings (public and private), borrowings under our credit facility and other financing transactions—to implement our growth strategy successfully. No assurance can be made that we will be able to raise necessary funds on satisfactory terms.

In July 2012, we amended and restated our senior secured credit facility with a syndicate of banks to, among other things, increase the committed amount from $775 million to $1 billion and the accordion feature from $225 million to $300 million, giving us the ability to expand the size of the facility up to an aggregate $1.3 billion for acquisitions or internal growth projects. The changes also included an increase of the inventory sublimit tranche from $125 million to $150 million. 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. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.

The key terms for rates under our amended credit facility, which are dependent on our leverage ratio (as defined in the credit agreement) are as follows:

•The applicable margins on Eurodollar borrowings will range from 1.75% to 2.75%.

•The applicable margins on alternate base rate borrowings will range from 0.75% to 1.75%.

•Letter of credit fees will range from 1.75% to 2.75%.


•	The commitment fee on the unused portion of the $1 billion facility amount will range from 0.375% to 0.50%.

Seventeen 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 amended credit facility matures in July 2017.

In February 2012, we issued $100 million under our existing 7.875% senior unsecured notes indenture for which the net proceeds were used to repay borrowings under our credit facility. The notes were issued at 101% of face value at an effective interest rate of 7.682%. See Note 7 to our Unaudited Condensed Consolidated Financial Statements for more information.

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In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. See Note 8 to our Unaudited Condensed Consolidated Financial Statements for more information.

At June 30, 2012, long-term debt totaled $796 million, consisting of $445 million outstanding under our credit facility (including $47.4 million borrowed under the inventory sublimit tranche) and a $351 million carrying amount of senior unsecured notes due in 2018.

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 carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

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. See Note 11 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the six months ended June 30, 2012 and 2011.

Net cash flows provided by our operating activities for the six months ended June 30, 2012 were $99.3 million compared to $9.4 million for the six months ended June 30, 2011. 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 provided by 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 or less cash. The increase in operating cash flow for the six months ended June 30, 2012 compared to the same period in 2011 was primarily due to higher cash earnings and lower working capital requirements.

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 smaller internal growth projects and distributions primarily with cash generated by our operations. Acquisition activities and large internal growth projects 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 for the six months ended June 30, 2012 and 2011 is as follows:

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	Six Months Ended June 30,
	2012		2011
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets	$	176	$	226
Refinery services assets	632		367
Supply and logistics assets	1,211		552
Other assets	—		244
Total maintenance capital expenditures	2,019		1,389
Growth capital expenditures:
Pipeline transportation assets	21,146		1,456
Refinery services assets	638		102
Supply and logistics assets ⁽¹⁾	61,793		1,575
Information technology systems upgrade projects	1,040		3,135
Total growth capital expenditures	84,617		6,268
Total maintenance and growth capital expenditures	86,636		7,657
Capital expenditures for business combinations, net of liabilities assumed:
Offshore pipelines	205,576		—
Capital expenditures related to equity investees ⁽²⁾	51,431		—
Total capital expenditures	$	343,643	$	7,657

(1) Includes the purchase of barge assets for $30.6 million (see below for more information).

(2) Represents our investment in the SEKCO pipeline joint venture (see below for more information).

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.

Growth Capital Expenditures

In April 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 and 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 and tankage in West Columbia, Texas 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. Once the refurbishment, tie-in and all interconnecting pipe are completed, estimated to be third quarter of 2012, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal. In addition, we have initiated construction of a 18-inch diameter loop of our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we expect will allow us to significantly expand our total service capabilities into the Texas City area by the second quarter of 2013.

During 2011, 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 in the fourth quarter of 2012, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and is expected to result in potential additional capacity of 24,000 DST per year of NaHS.

We are completing construction of a new crude-by-rail unloading terminal connected to our existing crude oil pipeline at Walnut Hill, Florida. This facility will be capable of handling unit train shipments of oil for direct deliveries to one refinery customer and indirect delivery, through third-party common carriers, to potentially multiple other markets in the Southeast. We anticipate this facility to be fully operational in August 2012.

We anticipate the costs of those projects above to be approximately $100 million in total, of which we have spent approximately $51 million since inception in 2011. We expect those remaining costs for the projects will be spent primarily in 2012.

We anticipate spending approximately $33 million to upgrade our refinery facilities in Wyoming and to bring

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the related pipeline back in service. We spent $2 million related to these projects during the first six months of 2012.

In February 2012, we purchased seven barges from Florida Marine Transporters, which previously had been subleased to us in connection with the acquisition of the black oil barge assets in August 2011. The cost of the seven barges totaled $30.6 million, which was funded with cash available under our credit facility.

Capital Expenditures Related to Business Combinations and Equity Investees

In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The purchase price, net of post-closing adjustments, was $205.6 million. We account for our ownership interests in Poseidon and Odyssey under the equity method of accounting. We accounted for our acquisition of GOPL using the acquisition method. See Note 2 in our Unaudited Condensed Consolidated Financial Statements for more information.

In December 2011, we formed Southeast Keathley Canyon Pipeline Company, LLC (or SEKCO) with Enterprise Products to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of Mexico. The new pipeline is expected to begin service by mid-2014. We expect to spend approximately $200 million for our share of the pipeline construction through 2014 and to reimburse Enterprise Products for our portion of previously incurred costs. We expect to pay approximately $80 million in 2012, of which we paid $51.4 million during the first half of 2012. The anchor producers, which have executed long-term transportation agreements, are responsible for most cost overruns and other costs incurred associated with weather-related delays.

Distributions to Unitholders

On August 14, 2012, we will pay a distribution of $0.46 per common unit totaling $36.6 million with respect to the second quarter of 2012 to common unitholders of record on August 1, 2012. This is the twenty-eighth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 8 to our Unaudited Condensed Consolidated Financial Statements.

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, 2011.

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, 2011, 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 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, 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;

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•	throughput levels and rates;


•	changes in, or challenges to, our tariff rates;


•	our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), 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 pipeline transportation systems and processing operations;


•	shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum products, or CO2 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;


•	changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers;


•	adverse rulings, judgments, or settlements in litigation or other legal or tax matters;


•	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, 2011 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.

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 2011 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 12 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

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communicated to them and our management to allow timely decisions regarding required disclosures.

There were no changes during the period covered by this report that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2011. 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, 2011. 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. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

In June 2011, the Financial Accounting Standards Board issued guidance on the presentation of comprehensive income in financial statements. Entities are required to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. We adopted this standard as of January 1, 2012 and will present net income and other comprehensive income in two separate, but consecutive, statements in our annual financial statements. The retrospective application did not have a material impact on our financial condition or results of operations. The following will be added to the Condensed Consolidated Financial Information footnote for Genesis Energy, L.P. and subsidiary guarantors in our annual financial statements:



	Year Ended December 31, 2011
	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Genesis Energy, L.P. Consolidated
Net income	$	51,249	$	—	$	87,007	$	5,139	$	(92,146	)	$	51,249
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps	—		—		—		—		—			—
Changes in derivative financial instruments -
interest rate swaps	—		—		—		—		—			—
Comprehensive income	51,249		—		87,007		5,139		(92,146		)	51,249
Comprehensive loss attributable to noncontrolling interests	—		—		—		—		—			—
Comprehensive income (loss) attributable to Genesis Energy, L.P.	$	51,249	$	—	$	87,007	$	5,139	$	(92,146	)	$	51,249

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	Year Ended December 31, 2010
	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Genesis Energy, L.P. Consolidated
Net (loss) income	$	(48,459	)	$	—	$	(36,648	)	$	7,205	$	27,361	$	(50,541	)
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps	—			—		2,112			—		—		2,112
Changes in derivative financial instruments -
interest rate swaps	—			—		(424		)	—		—		(424		)
Comprehensive (loss) income	(48,459		)	—		(34,960		)	7,205		27,361		(48,853		)
Comprehensive loss attributable to noncontrolling interests	—			—		1,223			—		—		1,223
Comprehensive (loss) income attributable to Genesis Energy, L.P.	$	(48,459	)	$	—	$	(33,737	)	$	7,205	$	27,361	$	(47,630	)



	Year Ended December 31, 2009
	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Genesis Energy, L.P. Consolidated
Net income	$	8,063	$	—	$	6,222		$	5,414	$	(13,521	)	$	6,178
Change in fair value of derivatives:
Current period reclassification in earnings -
interest rate swaps	—		—		784			—		—			784
Changes in derivative financial instruments -
interest rate swaps	—		—		(508		)	—		—			(508		)
Comprehensive income	8,063		—		6,498			5,414		(13,521		)	6,454
Comprehensive loss attributable to noncontrolling interests	—		—		1,742			—		—			1,742
Comprehensive income attributable to Genesis Energy, L.P.	$	8,063	$	—	$	8,240		$	5,414	$	(13,521	)	$	8,196

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Item 6. Exhibits.

(a) Exhibits.



3.1		Certificate of Limited Partnership of Genesis Energy, L.P. (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 Energy, L.P. (incorporated by reference to Exhibit 3.2 to Form 10-Q for the quarterly period ended June 30, 2011, File No. 011-12295).

3.3		Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (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 3, 2011, 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).



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



#	Pursuant to Item 601(b)(2) of Regulation S-K, Genesis agrees to furnish supplementally a copy of any omitted exhibit or schedule to the Securities and Exchange Commission upon request.

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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 3, 2012	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer