GENESIS ENERGY LP - Quarter Report: 2013 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, 2013

¨ 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. There were 82,900,988 Class A Common Units and 39,997 Class B Common Units outstanding as of July 31, 2013.

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GENESIS ENERGY, L.P.

TABLE OF CONTENTS



		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	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. Inventories	7
	3. Fixed Assets and Asset Retirement Obligations	8
	4. Equity Investees	8
	5. Intangible Assets	9
	6. Debt	10
	7. Partner's Capital and Distributions	10
	8. Business Segment Information	11
	9. Transactions with Related Parties	13
	10. Supplemental Cash Flow Information	14
	11. Derivatives	14
	12. Fair-Value Measurements	17
	13. Contingencies	17
	14. Subsequent Events	17
	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	40
Item 4.	Controls and Procedures	40
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults upon Senior Securities	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
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, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,668		$	11,282
Accounts receivable - trade, net	353,545			270,925
Inventories	87,908			87,050
Other	25,879			34,777
Total current assets	486,000			404,034
FIXED ASSETS, at cost	833,151			723,225
Less: Accumulated depreciation	(177,112		)	(157,944		)
Net fixed assets	656,039			565,281
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	154,694			157,385
EQUITY INVESTEES	604,380			549,235
INTANGIBLE ASSETS, net of amortization	68,786			75,065
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	38,107			33,618
TOTAL ASSETS	$	2,333,052		$	2,109,664
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	326,843		$	258,053
Accrued liabilities	69,460			54,598
Total current liabilities	396,303			312,651
SENIOR SECURED CREDIT FACILITY	319,100			500,000
SENIOR UNSECURED NOTES	700,835			350,895
DEFERRED TAX LIABILITIES	13,275			13,810
OTHER LONG-TERM LIABILITIES	17,091			15,813
COMMITMENTS AND CONTINGENCIES (Note 13)
PARTNERS’ CAPITAL:
Common unitholders, 82,940,985 and 81,202,752 units issued and outstanding at June 30, 2013 and December 31, 2012	886,448			916,495
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,333,052		$	2,109,664

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,
	2013			2012			2013			2012
REVENUES:
Supply and logistics	$	1,139,644		$	947,890		$	2,216,595		$	1,841,153
Refinery services	51,476			48,320			100,960			96,365
Pipeline transportation services	22,537			17,221			43,316			36,630
Total revenues	1,213,657			1,013,431			2,360,871			1,974,148
COSTS AND EXPENSES:
Supply and logistics product costs	1,066,886			883,176			2,068,431			1,719,045
Supply and logistics operating costs	46,171			40,707			95,365			78,623
Refinery services operating costs	32,821			31,050			65,264			61,829
Pipeline transportation operating costs	7,145			5,032			14,229			10,084
General and administrative	11,314			9,967			23,061			19,559
Depreciation and amortization	15,670			15,830			30,723			30,609
Total costs and expenses	1,180,007			985,762			2,297,073			1,919,749
OPERATING INCOME	33,650			27,669			63,798			54,399
Equity in earnings of equity investees	5,623			1,047			9,559			4,539
Interest expense	(12,254		)	(10,228		)	(23,695		)	(20,824		)
Income before income taxes	27,019			18,488			49,662			38,114
Income tax (expense) benefit	(117		)	96			86			74
NET INCOME	$	26,902		$	18,584		$	49,748		$	38,188
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.33		$	0.23		$	0.61		$	0.50
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	81,973			79,465			81,590			76,150

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
	2013	2012	2013			2012
Partners’ capital, January 1	81,203	71,965	$	916,495		$	792,638
Net income	—	—	49,748			38,188
Cash distributions	—	—	(79,795		)	(67,445		)
Issuance of common units for cash, net	—	5,750	—			169,421
Conversion of waiver units	1,738	1,738	—			—
Other	—	12	—			500
Partners' capital, June 30	82,941	79,465	$	886,448		$	933,302

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,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	49,748		$	38,188
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	30,723			30,609
Amortization of debt issuance costs and premium	2,128			1,784
Amortization of unearned income and initial direct costs on direct financing leases	(8,136		)	(8,456		)
Payments received under direct financing leases	10,631			10,926
Equity in earnings of investments in equity investees	(9,559		)	(4,539		)
Cash distributions of earnings of equity investees	15,475			10,715
Non-cash effect of equity-based compensation plans	8,710			1,617
Deferred and other tax liabilities	(536		)	(439		)
Unrealized gains on derivative transactions	(2,023		)	(1,176		)
Other, net	93			126
Net changes in components of operating assets and liabilities (Note 10)	(1,468		)	19,924
Net cash provided by operating activities	95,786			99,279
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(107,166		)	(80,378		)
Cash distributions received from equity investees - return of investment	5,539			7,309
Investments in equity investees	(66,207		)	(51,431		)
Acquisitions	—			(205,576		)
Proceeds from asset sales	626			654
Other, net	171			(915		)
Net cash used in investing activities	(167,037		)	(330,337		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	668,500			700,700
Repayments on senior secured credit facility	(849,400		)	(665,000		)
Proceeds from issuance of senior unsecured notes, including premium	350,000			101,000
Debt issuance costs	(8,157		)	(2,690		)
Issuance of common units for cash, net	—			169,421
Distributions to common unitholders	(79,795		)	(67,445		)
Other, net	(2,511		)	(703		)
Net cash provided by financing activities	78,637			235,283
Net increase in cash and cash equivalents	7,386			4,225
Cash and cash equivalents at beginning of period	11,282			10,817
Cash and cash equivalents at end of period	$	18,668		$	15,042

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 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, railcars, rail loading and unloading facilities, 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 selling the related by-product, sodium hydrosulfide (or “NaHS”, commonly pronounced "nash"); and


•	Supply and logistics services, which include 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, 2012.

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.

Immaterial Restatement

Revenues and cost of sales for 2012 include corrections to previously reported quarterly and annual amounts for the three and six months ended June 30, 2012. These corrections were made to present certain sales transactions on a gross basis that previously had been recorded on a net basis. The corrections had no effect on previously reported operating income, net income or Segment Margin.

2. Inventories

The major components of inventories were as follows:



	June 30, 2013		December 31, 2012
Petroleum products	$	63,242	$	58,943
Crude oil	16,241		15,885
Caustic soda	2,438		5,636
NaHS	5,965		6,573
Other	22		13
Total	$	87,908	$	87,050

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Inventories are valued at the lower of cost or market. The market value of inventories was below recorded costs by approximately $0.3 million at June 30, 2013, therefore we reduced the value of inventory in our Unaudited Condensed Consolidated Financial Statements for this difference. At December 31, 2012, market values of our inventories exceeded recorded costs.

3. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	June 30, 2013			December 31, 2012
Pipelines and related assets	$	261,049		$	226,831
Machinery and equipment	102,948			87,502
Transportation equipment	19,908			21,170
Marine vessels	297,951			298,054
Land, buildings and improvements	16,411			15,606
Office equipment, furniture and fixtures	5,125			4,964
Construction in progress	109,663			52,541
Other	20,096			16,557
Fixed assets, at cost	833,151			723,225
Less: Accumulated depreciation	(177,112		)	(157,944		)
Net fixed assets	$	656,039		$	565,281

Our depreciation expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Depreciation expense	$	11,070	$	9,549	$	21,565	$	18,044

4. 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, 2013 and December 31, 2012, the unamortized excess cost amounts totaled $229.1 million and $234 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.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Genesis’ share of operating earnings	$	8,221		$	3,595		$	14,871		$	9,633
Amortization of excess purchase price	(2,598		)	(2,548		)	(5,312		)	(5,094		)
Net equity in earnings	$	5,623		$	1,047		$	9,559		$	4,539
Distributions received	$	11,384		$	7,799		$	21,014		$	18,024

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	June 30, 2013		December 31, 2012
BALANCE SHEET DATA:
Assets
Current assets	$	69,945	$	74,906
Fixed assets, net	1,009,544		832,525
Other assets	8,591		10,202
Total assets	$	1,088,080	$	917,633
Liabilities and equity
Current liabilities	$	70,766	$	112,321
Other liabilities	164,210		134,731
Equity	853,104		670,581
Total liabilities and equity	$	1,088,080	$	917,633



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
INCOME STATEMENT DATA:
Revenues	$	45,528	$	36,452	$	86,268	$	73,970
Operating income	$	26,427	$	14,391	$	47,527	$	33,787
Net income	$	25,748	$	13,682	$	46,203	$	32,357

5. Intangible Assets

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



	June 30, 2013						December 31, 2012
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	72,725	$	21,929	$	94,654	$	69,167	$	25,487
Licensing agreements	38,678		24,474		14,204		38,678		22,892		15,786
Supplier relationships	—		—		—		36,469		36,469		—
Segment total	133,332		97,199		36,133		169,801		128,528		41,273
Supply & Logistics:
Customer relationships	35,430		27,485		7,945		35,430		26,403		9,027
Intangibles associated with lease	13,260		2,802		10,458		13,260		2,565		10,695
Trade names	—		—		—		18,888		18,888		—
Segment total	48,690		30,287		18,403		67,578		47,856		19,722
Other	19,890		5,640		14,250		18,932		4,862		14,070
Total	$	201,912	$	133,126	$	68,786	$	256,311	$	181,246	$	75,065

Our amortization expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Amortization expense	$	3,609	$	5,355	$	7,236	$	10,870

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



Remainder of	2013	$	7,329
	2014	$	12,440
	2015	$	10,631
	2016	$	9,170
	2017	$	8,007

6. Debt

Our obligations under debt arrangements consisted of the following:



	June 30, 2013		December 31, 2012
Senior secured credit facility	$	319,100	$	500,000
7.875% senior unsecured notes (including unamortized premium of $835 and $895 in 2013 and 2012, respectively)	350,835		350,895
5.750% senior unsecured notes	350,000		—
Total long-term debt	$	1,019,935	$	850,895

As of June 30, 2013, 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, 2013, we had $319.1 million borrowed under our $1 billion credit facility, with $73.4 million of the borrowed amount designated as a loan under the inventory sublimit. The credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $14.4 million was outstanding at June 30, 2013. 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. The total amount available for borrowings under our credit facility at June 30, 2013 was $666.5 million.

Senior Unsecured Notes

In November 2010, we issued $250 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2018 (the "2018 Notes"). The 2018 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year. In February 2012, we issued an additional $100 million of aggregate principal amount of the 2018 Notes. The additional 2018 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 of the 2018 Notes under the indenture to $350 million.

On February 8, 2013, we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes (the "2021 Notes"). The 2021 Notes were sold at face value. Interest payments are due on February 15 and August 15 of each year, beginning August 15, 2013. The 2021 Notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes.

The 2018 and the 2021 Notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and are each fully and unconditionally guaranteed, jointly and severally, by certain of our wholly-owned subsidiaries. We have the right to redeem the 2018 Notes at any time after December 15, 2014 at a premium to the face amount of the notes that varies based on the time remaining to maturity of the 2018 Notes. Prior to December 15, 2013, we may also redeem up to 35% of the principal amount of the 2018 Notes for 107.875% of the face amount with the proceeds from an equity offering of our common units. We have the right to redeem the 2021 Notes at any time after February 15, 2017, at a premium to the face amount of the 2021 Notes that varies based on the time remaining to maturity on the 2021 Notes. Prior to February 15, 2016, we may also redeem up to 35% of the principal amount of the 2021 Notes for 105.75% of the face amount with the proceeds from an equity offering of our common units.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Partners’ Capital and Distributions

At June 30, 2013, our outstanding common units consisted of 82,900,988 Class A units and 39,997 Class B units.

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 1,738,000 units each. 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.

On August 14, 2012, our Class 2 waiver units became convertible as we paid a distribution of $0.46 per common unit and satisfied the conversion coverage ratio requirement. All Class 2 waiver units were converted into common units by September 30, 2012.

On May 15, 2013, our Class 3 waiver units became convertible as we paid a distribution of $0.4975 per common unit and satisfied the conversion coverage ratio requirement. All Class 3 waiver units were converted into common units by June 30, 2013.

At June 30, 2013, we had 1,738,233 waiver units outstanding comprised of the Class 4 waiver units.

Distributions

We paid or will pay the following distributions in 2012 and 2013:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2012
1^st Quarter	May 15, 2012		$	0.4500	$	35,768
2^nd Quarter	August 14, 2012		$	0.4600	$	36,563
3^rd Quarter	November 14, 2012		$	0.4725	$	38,375
4^th Quarter	February 14, 2013		$	0.4850	$	39,390
2013
1^st Quarter	May 15, 2013		$	0.4975	$	40,405
2^nd Quarter	August 14, 2013	⁽¹⁾	$	0.5100	$	42,303

(1) This distribution will be paid to unitholders of record as of August 1, 2013.

8. Business Segment Information

Our operations consist of three operating segments:


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


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


•	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.

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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the periods presented below was as follows:



	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended June 30, 2013
Segment margin (a)	$	26,456	$	18,696		$	25,290		$	70,442
Capital expenditures (b)	$	37,556	$	1,312		$	38,448		$	77,316
Revenues:
External customers	$	19,180	$	54,288		$	1,140,189		$	1,213,657
Intersegment (c)	3,357		(2,812		)	(545		)	—
Total revenues of reportable segments	$	22,537	$	51,476		$	1,139,644		$	1,213,657
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		$	949,458		$	1,013,431
Intersegment (c)	3,823		(2,255		)	(1,568		)	—
Total revenues of reportable segments	$	17,221	$	48,320		$	947,890		$	1,013,431
Six Months Ended June 30, 2013
Segment margin (a)	$	51,652	$	36,661		$	54,194		$	142,507
Capital expenditures (b)	$	121,408	$	1,664		$	56,059		$	179,131
Revenues:
External customers	$	36,485	$	106,467		$	2,217,919		$	2,360,871
Intersegment (c)	6,831		(5,507		)	(1,324		)	—
Total revenues of reportable segments	$	43,316	$	100,960		$	2,216,595		$	2,360,871
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		$	1,844,826		$	1,974,148
Intersegment (c)	8,256		(4,583		)	(3,673		)	—
Total revenues of reportable segments	$	36,630	$	96,365		$	1,841,153		$	1,974,148

Total assets by reportable segment were as follows:



	June 30, 2013		December 31, 2012
Pipeline transportation	$	994,009	$	890,652
Refinery services	419,137		414,170
Supply and logistics	857,068		750,347
Other assets	62,838		54,495
Total consolidated assets	$	2,333,052	$	2,109,664

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Segment Margin	$	70,442		$	62,831		$	142,507		$	123,083
Corporate general and administrative expenses	(10,305		)	(8,707		)	(21,142		)	(17,328		)
Depreciation and amortization	(15,670		)	(15,830		)	(30,723		)	(30,609		)
Interest expense	(12,254		)	(10,228		)	(23,695		)	(20,824		)
Distributable cash from equity investees in excess of equity in earnings	(4,891		)	(6,752		)	(11,455		)	(13,485		)
Non-cash items not included in segment margin	960			(1,577		)	(3,335		)	(253		)
Cash payments from direct financing leases in excess of earnings	(1,263		)	(1,249		)	(2,495		)	(2,470		)
Income before income taxes	$	27,019		$	18,488		$	49,662		$	38,114

(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. In addition to construction of internal growth projects, capital spending in our pipeline transportation segment included $1.7 million and $66.2 million during the three and six months ended June 30, 2013 and $17.9 million and $51.4 million during the three and six months ended June 30, 2012 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.


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

9. 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,
	2013		2012		2013		2012
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	808	$	660	$	1,481	$	1,273
Petroleum products sales to Davison family businesses	289		374		644		686
Petroleum products sales to an affiliate of the Quintana Group ⁽²⁾	—		4,578		—		14,766
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	150		150		300		300
Marine operating fuel and expenses provided by an affiliate of the Quintana Group ⁽²⁾	—		2,244		—		4,201


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


(2)	The Quintana Group monetized all of its remaining investment in our common units on October 5, 2012. Transactions with the Quintana Group are included in the above table as related party transactions through October 5, 2012.

Amount due from Related Party

At June 30, 2013 and December 31, 2012 Sandhill Group, LLC owed us $0.3 million and $0.2 million for purchases of CO₂.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2013			2012
(Increase) decrease in:
Accounts receivable	$	(82,346	)	$	6,698
Inventories	(858		)	28,146
Other current assets	11,135			5,197
Increase (decrease) in:
Accounts payable	66,860			(9,549		)
Accrued liabilities	3,741			(10,568		)
Net changes in components of operating assets and liabilities	$	(1,468	)	$	19,924

Payments of interest and commitment fees were $18.9 million and $21.6 million for the six months ended June 30, 2013 and June 30, 2012, respectively.

At June 30, 2013 and June 30, 2012, we had incurred liabilities for fixed and intangible asset additions totaling $20.8 million and $8.1 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.

At June 30, 2013, we had incurred liabilities for other asset additions totaling $0.2 million that had not been paid at the end of the second quarter, and, therefore, were not included in the caption "Other, net" under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

11. 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 of crude oil, fuel oil and petroleum products. 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.

At June 30, 2013, we had the following outstanding derivative commodity 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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	321		107
Weighted average contract price per bbl	$	94.64	$	95.99
Diesel:
Contract volumes (1,000 bbls)	51		37
Weighted average contract price per gal	$	2.85	$	2.86
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	532		10
Weighted average contract price per bbl	$	89.93	$	92.00
Crude oil options:
Contract volumes (1,000 bbls)	320		50
Weighted average premium received	$	1.43	$	0.30
RBOB:
Contract volumes (1,000 bbls)	10		—
Weighted average premium received	$	0.06	$	—

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. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at June 30, 2013 and December 31, 2012:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	June 30, 2013			December 31, 2012
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	688		$	758
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(688		)	(758		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,265	)	$	(3,357	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,265			3,357
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—

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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of June 30, 2013, we had a net broker receivable of approximately $3.6 million (consisting of initial margin of $3.2 million increased by $0.4 million of variation margin). As of December 31, 2012, we had a net broker receivable of approximately $3.6 million (consisting of initial margin of $4.1 million reduced by $0.5 million of variation margin that had been returned to us). At June 30, 2013 and December 31, 2012, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended June 30,				Six Months Ended June 30,
		2013		2012		2013		2012
Commodity derivatives - futures and call options:
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	$	5,148	$	13,569	$	1,645	$	2,858
Total commodity derivatives		$	5,148	$	13,569	$	1,645	$	2,858

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. 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 for identical assets and liabilities;


(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, 2013							December 31, 2012
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	688		$	—	$	—	$	758		$	—	$	—
Liabilities	$	(1,265	)	$	—	$	—	$	(3,357	)	$	—	$	—

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 11 for additional information on our derivative instruments.

Other Fair Value Measurements

We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates for similar instruments with comparable maturities. At June 30, 2013, our senior unsecured notes had a carrying value of $700.8 million and a fair value of $717.9 million, compared to $350.9 million and $373.2 million, respectively, at December 31, 2012. 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.

13. Contingencies

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

14. Subsequent Events

We have agreed to acquire substantially all the assets of the downstream transportation business of Hornbeck Offshore Transportation, LLC for approximately $230 million. The business is primarily comprised of nine barges and nine tug boats which transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

15. Condensed Consolidating Financial Information

Our $700 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 and accordingly has no ability to service obligations on the 2018 and 2021 Notes. Each subsidiary guarantor and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P. See Note 6 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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

June 30, 2013



	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	$	4	$	—	$	18,233		$	431		$	—		$	18,668
Other current assets	892,978		—		444,424			44,647			(914,717		)	467,332
Total current assets	892,982		—		462,657			45,078			(914,717		)	486,000
Fixed assets, at cost	—		—		718,382			114,769			—			833,151
Less: Accumulated depreciation	—		—		(162,270		)	(14,842		)	—			(177,112		)
Net fixed assets	—		—		556,112			99,927			—			656,039
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	23,705		—		244,309			155,070			(161,497		)	261,587
Equity investees	—		—		604,380			—			—			604,380
Investments in subsidiaries	1,000,004		—		105,702			—			(1,105,706		)	—
Total assets	$	1,916,691	$	—	$	2,298,206		$	300,075		$	(2,181,920	)	$	2,333,052
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	10,308	$	—	$	1,270,488		$	29,996		$	(914,489	)	$	396,303
Senior secured credit facility	319,100		—		—			—			—			319,100
Senior unsecured notes	700,835		—		—			—			—			700,835
Deferred tax liabilities	—		—		13,275			—			—			13,275
Other liabilities	—		—		13,453			164,955			(161,317		)	17,091
Total liabilities	1,030,243		—		1,297,216			194,951			(1,075,806		)	1,446,604
Partners’ capital	886,448		—		1,000,990			105,124			(1,106,114		)	886,448
Total liabilities and partners’ capital	$	1,916,691	$	—	$	2,298,206		$	300,075		$	(2,181,920	)	$	2,333,052

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 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	$	10	$	—	$	11,214		$	58		$	—		$	11,282
Other current assets	745,589		—		367,837			41,533			(762,207		)	392,752
Total current assets	745,599		—		379,051			41,591			(762,207		)	404,034
Fixed assets, at cost	—		—		617,519			105,706			—			723,225
Less: Accumulated depreciation	—		—		(144,882		)	(13,062		)	—			(157,944		)
Net fixed assets	—		—		472,637			92,644			—			565,281
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	17,737		—		254,423			157,604			(163,696		)	266,068
Equity investees	—		—		549,235			—			—			549,235
Investments in subsidiaries	1,006,415		—		102,707			—			(1,109,122		)	—
Total assets	$	1,769,751	$	—	$	2,083,099		$	291,839		$	(2,035,025	)	$	2,109,664
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,361	$	—	$	1,048,937		$	23,567		$	(762,214	)	$	312,651
Senior secured credit facility	500,000		—		—			—			—			500,000
Senior unsecured notes	350,895		—		—			—			—			350,895
Deferred tax liabilities	—		—		13,810			—			—			13,810
Other liabilities	—		—		13,044			166,282			(163,513		)	15,813
Total liabilities	853,256		—		1,075,791			189,849			(925,727		)	1,193,169
Partners’ capital	916,495		—		1,007,308			101,990			(1,109,298		)	916,495
Total liabilities and partners’ capital	$	1,769,751	$	—	$	2,083,099		$	291,839		$	(2,035,025	)	$	2,109,664

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2013



	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	$	—		$	—	$	1,134,554		$	35,124		$	(30,034	)	$	1,139,644
Refinery services	—			—		51,682			3,796			(4,002		)	51,476
Pipeline transportation services	—			—		15,731			6,806			—			22,537
Total revenues	—			—		1,201,967			45,726			(34,036		)	1,213,657
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,109,870			33,221			(30,034		)	1,113,057
Refinery services operating costs	—			—		32,915			3,516			(3,610		)	32,821
Pipeline transportation operating costs	—			—		6,668			477			—			7,145
General and administrative	—			—		11,287			27			—			11,314
Depreciation and amortization	—			—		14,760			910			—			15,670
Total costs and expenses	—			—		1,175,500			38,151			(33,644		)	1,180,007
OPERATING INCOME	—			—		26,467			7,575			(392		)	33,650
Equity in earnings of subsidiaries	39,133			—		3,533			—			(42,666		)	—
Equity in earnings of equity investees	—			—		5,623			—			—			5,623
Interest (expense) income, net	(12,231		)	—		4,030			(4,053		)	—			(12,254		)
Income before income taxes	26,902			—		39,653			3,522			(43,058		)	27,019
Income tax expense	—			—		(87		)	(30		)	—			(117		)
NET INCOME	$	26,902		$	—	$	39,566		$	3,492		$	(43,058	)	$	26,902

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GENESIS ENERGY, L.P.

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	$	—		$	—	$	940,232	$	32,159		$	(24,501	)	$	947,890
Refinery services	—			—		45,311		6,744			(3,735		)	48,320
Pipeline transportation services	—			—		10,869		6,352			—			17,221
Total revenues	—			—		996,412		45,255			(28,236		)	1,013,431
COSTS AND EXPENSES:
Supply and logistics costs	—			—		920,360		28,022			(24,499		)	923,883
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	—			—		14,932		898			—			15,830
Total costs and expenses	—			—		979,260		35,213			(28,711		)	985,762
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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2013



	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	$	—		$	—	$	2,205,043	$	74,069		$	(62,517	)	$	2,216,595
Refinery services	—			—		99,449		9,359			(7,848		)	100,960
Pipeline transportation services	—			—		29,857		13,459			—			43,316
Total revenues	—			—		2,334,349		96,887			(70,365		)	2,360,871
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,158,801		67,512			(62,517		)	2,163,796
Refinery services operating costs	—			—		64,082		8,798			(7,616		)	65,264
Pipeline transportation operating costs	—			—		13,422		807			—			14,229
General and administrative	—			—		23,001		60			—			23,061
Depreciation and amortization	—			—		28,911		1,812			—			30,723
Total costs and expenses	—			—		2,288,217		78,989			(70,133		)	2,297,073
OPERATING INCOME	—			—		46,132		17,898			(232		)	63,798
Equity in earnings of subsidiaries	73,385			—		9,771		—			(83,156		)	—
Equity in earnings of equity investees	—			—		9,559		—			—			9,559
Interest (expense) income, net	(23,637		)	—		8,077		(8,135		)	—			(23,695		)
Income before income taxes	49,748			—		73,539		9,763			(83,388		)	49,662
Income tax benefit (expense)	—			—		170		(84		)	—			86
NET INCOME	$	49,748		$	—	$	73,709	$	9,679		$	(83,388	)	$	49,748

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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	$	—		$	—	$	1,827,913	$	64,338		$	(51,098	)	$	1,841,153
Refinery services	—			—		93,907		9,389			(6,931		)	96,365
Pipeline transportation services	—			—		23,785		12,845			—			36,630
Total revenues	—			—		1,945,605		86,572			(58,029		)	1,974,148
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,792,002		56,762			(51,096		)	1,797,668
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	—			—		28,819		1,790			—			30,609
Total costs and expenses	—			—		1,909,826		68,142			(58,219		)	1,919,749
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 Cash Flows

Six Months Ended June 30, 2013



	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	$	(86,739	)	$	—	$	245,918		$	17,342		$	(80,735	)	$	95,786
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(98,050		)	(9,116		)	—			(107,166		)
Cash distributions received from equity investees - return of investment	5,585			—		5,539			—			(5,585		)	5,539
Investments in equity investees	—			—		(66,207		)	—			—			(66,207		)
Repayments on loan to non-guarantor subsidiary	—			—		2,199			—			(2,199		)	—
Proceeds from asset sales	—			—		626			—			—			626
Other, net	—			—		171			—			—			171
Net cash provided by (used) in investing activities	5,585			—		(155,722		)	(9,116		)	(7,784		)	(167,037		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	668,500			—		—			—			—			668,500
Repayments on senior secured credit facility	(849,400		)	—		—			—			—			(849,400		)
Proceeds from issuance of senior unsecured notes, including premium	350,000			—		—			—			—			350,000
Debt issuance costs	(8,157		)	—		—			—			—			(8,157		)
Distributions to partners/owners	(79,795		)	—		(79,795		)	(6,545		)	86,340			(79,795		)
Other, net	—			—		(3,382		)	(1,308		)	2,179			(2,511		)
Net cash provided by (used in) financing activities	81,148			—		(83,177		)	(7,853		)	88,519			78,637
Net (decrease) increase in cash and cash equivalents	(6		)	—		7,019			373			—			7,386
Cash and cash equivalents at beginning of period	10			—		11,214			58			—			11,282
Cash and cash equivalents at end of period	$	4		$	—	$	18,233		$	431		$	—		$	18,668

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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		)	—
Proceeds from asset sales	—			—		654			—			—			654
Other, net	—			—		(120		)	(795		)	—			(915		)
Net cash used in 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
Debt issuance costs	(2,690		)	—		—			—			—			(2,690		)
Distributions to partners/owners	(67,445		)	—		(67,445		)	(8,750		)	76,195			(67,445		)
Issuance of common units for cash, net	169,421			—		169,421			795			(170,216		)	169,421
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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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 for the year ended December 31, 2012.

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


•	Overview


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income of $26.9 million, or $0.33 per common unit during the three months ended June 30, 2013 (“2013 Quarter”) compared to net income of $18.6 million or $0.23 per common unit during the three months ended June 30, 2012 (“2012 Quarter”).

Available Cash before Reserves increased $2.5 million, or 6%, in the 2013 Quarter (as compared to the 2012 Quarter) to $45.7 million consistent with the increase in net income described above. See “Financial Measures” below for additional information on Available Cash before Reserves.

The significant factor benefiting net income and Available Cash before Reserves was improved operating results by each of our segments. Segment Margin (as described below in “Financial Measures”) increased by $7.6 million, or 12%, in the 2013 Quarter, as compared to the 2012 Quarter. The increase resulted from improvement in Segment Margin in our pipeline transportation, refinery services and supply and logistics segments of 27%, 8% and 2%, respectively.

However, in the 2013 Quarter, a number of items combined to negatively impact our pipeline transportation and supply and logistics segments.

In our pipeline transportation segment, operating results from our offshore crude oil pipelines were adversely affected by approximately $2.5 million due to production variations at connected fields and unplanned downtime on the Eugene Island System.

In our supply and logistics segment, operating results were negatively impacted by approximately $2.9 million due to several items including (1) expenses for repairs to one of our marine vessels as well as foregone Segment Margin attributable to that vessel's downtime, (2) demurrage costs incurred due to damage to a river lock caused by a third party operator that idled certain of our barge activities during a shipment of petroleum products, (3) downtime as a result of a turnaround at our crude processing facility in Wyoming, (4) ineffectiveness of hedging certain crude oil volumes, and (5) volumetric measurement losses associated with our crude oil gathering and marketing activities.

The Available Cash before Reserves increase in the 2013 Quarter was also offset by approximately $1.1 million of equity-based compensation costs related to the increase in the market price of our common units. The market price of our common units at June 30, 2013 was $51.83 compared to $48.22 at March 31, 2013, representing a 7% increase.

A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.

We have agreed to acquire for approximately $230 million substantially all the assets of the downstream transportation business of Hornbeck Offshore Transportation, LLC (“Hornbeck”). The business is primarily comprised of nine barges and nine tug boats which transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. At the closing of the transaction, we expect to enter into transition service agreements to facilitate a smooth transition of operations and uninterrupted services for both employees and customers.

The Hornbeck acquisition complements and further integrates our existing operations, including our Genesis Marine inland barge business, our crude oil and heavy refined products storage and blending terminals as well as our crude oil pipeline systems. The acquisition is subject to usual and customary closing conditions, including regulatory approvals and consents, and would be expected to close by the end of the third quarter of 2013.

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Distribution Increase

In July 2013, we declared our thirty-second consecutive increase in our quarterly distribution to our common unitholders relative to the second quarter of 2013. During that period, twenty-seven of those quarterly increases have been 10% or greater year-over-year. In August 2013, we will pay a distribution of $0.51 per unit representing a 10.9% increase from our distribution of $0.46 per unit related to the second quarter of 2012. During the second quarter of 2013, we paid a distribution of $0.4975 per unit related to the first quarter of 2013.

Financial Measures

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 8 to our Unaudited Condensed Consolidated Financial Statements.

Available Cash before Reserves

This Quarterly Report on Form 10-Q 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, including applicable pro forma presentations, 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 investments. 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 certain 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), unrealized gains and losses on derivative transactions not designated as 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.

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



	Three Months Ended June 30,
	2013			2012
	(in thousands)
Net income	$	26,902		$	18,584
Depreciation and amortization	15,670			15,830
Cash received from direct financing leases not included in income	1,263			1,249
Cash effects of sales of certain assets	294			294
Effects of distributable cash generated by equity method investees not included in income	4,891			6,752
Cash effects of equity-based compensation plans	(1,896		)	(477		)
Non-cash legacy stock appreciation rights plan expense	705			1,013
Expenses related to acquiring or constructing assets that provide new sources of cash flow	667			180
Unrealized (gain) loss on derivative transactions excluding fair value hedges	(1,971		)	816
Maintenance capital expenditures	(1,015		)	(806		)
Non-cash tax benefit	(213		)	(402		)
Other items, net	412			181
Available Cash before Reserves	$	45,709		$	43,214

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2013 Quarter increased $200.2 million, or 20% from the 2012 Quarter. Additionally, our costs and expenses increased $194.2 million, or 20% between the two periods.

Our revenues for the six months ended June 30, 2013 increased $386.7 million, or 20% from the six months ended June 30, 2012. Costs and expenses increased $377.3 million, or 20% between the six month periods.

The substantial 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 operations. Revenues and costs between the six month periods was 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 33% quarter to quarter and 30% 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") was consistent between the quarterly periods, increasing less than 1% to $94.22 per barrel in the second quarter of 2013, as compared to $93.49 per barrel in the second quarter of 2012. Average closing prices for WTI crude oil on the NYMEX decreased 4% from $98.21 per barrel in the first six months of 2012 to $94.30 per barrel in the first six months of 2013.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2013 and June 30, 2012 was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Pipeline transportation	$	26,456	$	20,785	$	51,652	$	46,132
Refinery services	18,696		17,278		36,661		34,527
Supply and logistics	25,290		24,768		54,194		42,424
Total Segment Margin	$	70,442	$	62,831	$	142,507	$	123,083

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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,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	9,923		$	7,312		$	19,404		$	14,103
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees	9,688			7,573			19,713			18,187
CO₂ tariffs and revenues from direct financing leases of CO₂ pipelines	6,930			6,447			13,754			13,038
Sales of onshore crude oil pipeline loss allowance volumes	3,419			1,530			5,642			4,783
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(4,997		)	(3,554		)	(9,865		)	(6,923		)
Payments received under direct financing leases not included in income	1,263			1,249			2,495			2,470
Other	230			228			509			474
Segment Margin	$	26,456		$	20,785		$	51,652		$	46,132

Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	54,929			53,653			54,175			49,094
Jay	38,062			18,100			33,107			18,460
Mississippi	18,946			18,930			18,965			18,597
Offshore crude oil pipelines:
CHOPS⁽¹⁾	126,819			43,407			120,531			72,468
Poseidon ⁽¹⁾	220,687			214,470			212,663			202,108
Odyssey ⁽¹⁾	44,493			36,091			43,837			38,080
GOPL	9,335			18,125			9,132			21,367
CO₂ pipeline (Mcf/day):
Free State	227,168			166,289			217,844			172,150

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

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

Pipeline transportation Segment Margin for the 2013 Quarter increased $5.7 million, or 27%. In the 2013 Quarter, the operating results from our offshore crude oil pipelines were adversely affected by approximately $2.5 million due to production variations at connected fields and unplanned downtime on the Eugene Island System. Other significant components of this change were as follows:

•

Crude oil tariff revenues of onshore crude oil pipelines increased $2.6 million primarily due to upward tariff indexing of approximately 8.6% for our FERC-regulated pipelines effective in July 2012 and increased total throughput volumes of 21,254 barrels per day, primarily from our Jay pipeline system. Additional barrels received at our crude-by-rail unloading terminal at Walnut Hill, Florida increased volumes on the Jay pipeline system.


•	Segment Margin from our offshore crude oil pipelines increased $2.1 million reflecting an increased contribution from CHOPS. In the 2012 Quarter, ongoing improvements by producers at the connected production fields resulted in lower volumes transported on CHOPS.


•	Revenues from sales of onshore crude oil pipeline loss allowance volumes increased Segment Margin by $1.9 million due to an increase of approximately 19,800 barrels sold in the 2013 Quarter as compared to the 2012 Quarter.


•	Onshore pipeline operating costs, excluding non-cash charges, increased due to employee compensation and related benefit costs and general increases in operating costs inclusive of increased safety program costs.

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•

Volumes on our Free State CO₂ pipeline system increased 60,879 Mcf per day, or 37%, in the 2013 Quarter as compared to the 2012 Quarter. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, increases in volumes on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

Segment Margin for our pipeline transportation segment increased $5.5 million, or 12% between the six month periods. In the 2013 six month period, the operating results from our offshore crude oil pipelines were adversely affected by approximately $2.5 million due to production variations at connected fields and unplanned downtime on the Eugene Island System. Other significant components of this change were as follows:

•

Crude oil tariff revenues of onshore crude oil pipelines increased $5.3 million primarily due to upward tariff indexing of approximately 8.6% for our FERC-regulated pipelines effective in July 2012 and increased total throughput volumes of 20,096 barrels per day, primarily from our Texas and Jay pipeline systems. Additional barrels received at our crude-by-rail unloading terminal at Walnut Hill, Florida, increased volumes on the Jay pipeline system.


•	Segment Margin from our offshore crude oil pipelines increased $1.5 million reflecting an increased contribution from CHOPS. In the first six months of 2012, ongoing improvements by producers at the connected production fields resulted in lower volumes transported on CHOPS.


•	Revenues from sales of onshore crude oil pipeline loss allowance volumes increased Segment Margin by $0.9 million due to an increase of approximately 12,900 barrels sold in the first half of 2013 as compared to the first half of 2012, partially offset by a decrease (an average of $4 per barrel) in crude oil prices.


•	Onshore pipeline operating costs, excluding non-cash charges, increased due to required five-year integrity testing expenditures on our onshore pipelines, employee compensation and related benefit costs and general increases in operating costs inclusive of increased safety program costs.

•

Volumes on our Free State CO₂ pipeline system increased 45,694 Mcf per day, or 27%, in the first six months of 2013 as compared to the first six months of 2012. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, increases in volumes on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

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Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Volumes sold (in Dry short tons "DST"):
NaHS volumes	36,665			39,184			73,287			72,949
NaOH (caustic soda) volumes	21,720			14,670			40,950			35,588
Total	58,385			53,854			114,237			108,537

Revenues (in thousands):
NaHS revenues	$	40,462		$	40,239		$	79,297		$	77,034
NaOH (caustic soda) revenues	12,695			8,447			24,097			20,275
Other revenues	1,131			1,889			3,073			3,639
Total external segment revenues	$	54,288		$	50,575		$	106,467		$	100,948

Segment Margin (in thousands)	$	18,696		$	17,278		$	36,661		$	34,527

Average index price for NaOH per DST ⁽¹⁾	$	626		$	548		$	614		$	559
Raw material and processing costs as % of segment revenues	49		%	51		%	49		%	49		%

(1) Source: IHS Chemical

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

Refinery services Segment Margin for the 2013 Quarter increased $1.4 million, or 8%. 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 and the other components referenced below, partially offset by decreased sales volumes. NaHS sales volumes decreased between the quarterly periods primarily due to a decrease in sales to South American customers in the 2013 Quarter. Sales volumes between quarters to customers in South America can fluctuate due to timing of bulk deliveries. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point.

•

Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although we were able to partially offset our increased raw materials costs with operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition (including economies of scale) and utilization of caustic soda in our (and our customers') operations, and our logistics management capabilities.

•

Caustic soda sales volumes increased 48%. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities, however these sales did have a positive impact to Segment Margin in the 2013 Quarter. 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 $626 per DST in the second quarter of 2013 compared to $548 per DST during the second quarter of 2012. 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

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storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

Refinery services Segment Margin increased $2.1 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 increased sales volumes and an increase in the average index price for caustic soda, partially offset by other components referenced below. NaHS sales volumes increased primarily due to increased demand from customers in the pulp and paper industry, however this increase was partially offset by a decrease in sales to South American customers (due to timing of bulk deliveries). 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. The mix of NaHS sales volumes to which these adjustments applied reduced NaHS revenues in the first six months of 2013.

•

Caustic soda sales volumes increased 15%. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities, however these sales did have a positive impact to Segment Margin in the first half of 2013. 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 $614 per DST in the first six months of 2013 compared to $559 per DST during the first six months of 2012. 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 somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Supply and Logistics Segment

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Supply and logistics revenue	$	1,139,644		$	947,890		$	2,216,595		$	1,841,153
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(1,068,857		)	(882,360		)	(2,070,455		)	(1,720,221		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(45,797		)	(40,289		)	(92,572		)	(77,919		)
Other	300			(473		)	626			(589		)
Segment Margin	$	25,290		$	24,768		$	54,194		$	42,424

Volumes of crude oil and petroleum products (barrels per day)	119,648			90,211			113,552			87,069

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The average market prices of crude oil and petroleum products increased less than 1% and decreased 4% between the three and six month periods, respectively, however that price volatility has a limited impact on our Segment Margin.

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

Segment Margin for our supply and logistics segment increased by $0.5 million, or 2% between the two second quarter periods. In the 2013 Quarter, our operating results were negatively impacted by approximately $2.9 million for several items including (1) expenses for repairs to one of our marine vessels as well as foregone Segment Margin attributable to that vessel's downtime, (2) demurrage costs incurred due to damage to a river lock caused by a third party operator that idled certain of our barge activities during a shipment of petroleum products, (3) downtime as a result of a turnaround at our crude processing facility in Wyoming, (4) ineffectiveness of hedging certain crude oil volumes, and (5) volumetric measurement losses associated with our crude oil gathering and marketing activities.

The overall increase in our supply and logistics Segment Margin was primarily due to a 33% increase in crude and petroleum products volumes, however the overall composition of our supply and logistics revenue streams limited the relative impact on Segment Margin. Segment Margin also increased due to the contribution from our crude oil rail loading and unloading operations completed in the second half of 2012. Our operating costs, excluding non-cash charges, increased 14% between the two second quarters primarily due to employee compensation and related benefit costs. Increases in those costs are the result of higher employee counts from our expanded trucking fleet and the recent growth in our crude oil rail loading and unloading operations.

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

Segment Margin for our supply and logistics segment increased by $11.8 million, or 28%, during the first six months of 2013. In the 2013 six month period, our operating results were negatively impacted by approximately $2.9 million for several items including (1) expenses for repairs to one of our marine vessels as well as foregone Segment Margin attributable to that vessel's downtime, (2) demurrage costs incurred due to damage to a river lock caused by a third party operator that idled certain of our barge activities during a shipment of petroleum products, (3) downtime as a result of a turnaround at our crude processing facility in Wyoming, (4) ineffectiveness of hedging certain crude oil volumes, and (5) volumetric measurement losses associated with our crude oil gathering and marketing activities.

The overall increase in our supply and logistics Segment Margin during the first six months of 2013 resulted primarily from a 30% increase in crude and petroleum products volumes. Segment Margin also increased due to the contribution from our crude oil rail loading and unloading operations completed in the second half of 2012. Our operating costs, excluding non-cash charges, increased 19% between the two six month periods primarily due to employee compensation and related benefit costs. Increases in those costs are the result of higher employee counts from our expanded trucking fleet and the recent growth in our crude oil rail loading and unloading operations.

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	5,802	$	5,753	$	11,320	$	11,154
Segment	2,869		2,870		5,316		5,106
Equity-based compensation plan expense	1,976		1,164		5,542		2,511
Third party costs related to business development activities and growth projects	667		180		883		788
Total general and administrative expenses	$	11,314	$	9,967	$	23,061	$	19,559

Total general and administrative expenses increased $1.3 million and $3.5 million between the three and six month periods, respectively, primarily due to an increase in equity-based compensation plan expenses not included in Segment Margin and increases in third party costs related to business and growth transactions. Increases in the market price of our common units resulted in increased expenses related to our equity-based compensation plans. The market price of our common units at June 30, 2013 was $51.83 compared to $35.72 at December 31, 2012, representing a 45% increase.

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Depreciation and amortization expense



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Depreciation expense	$	11,070	$	9,549	$	21,565	$	18,044
Amortization of intangible assets	3,609		5,355		7,236		10,870
Amortization of CO2 volumetric production payments	991		926		1,922		1,695
Total depreciation and amortization expense	$	15,670	$	15,830	$	30,723	$	30,609

Total depreciation and amortization expense was relatively constant between the three and six month periods as increases in depreciation expense were offset by decreases in amortization of intangible assets. Depreciation expense increased $1.5 million and $3.5 million between the three and six month periods, respectively, primarily as a result of recently completed internal growth projects. Amortization of intangible assets decreased $1.7 million and $3.6 million between the three and six month periods, respectively, as we amortize our intangible assets over the period in which we expect them to contribute to our future cash flows.

Interest expense, net



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	2,417		$	3,225		$	5,220		$	7,334
Interest expense, senior unsecured notes	11,891			6,862			21,715			12,750
Amortization of debt issuance costs and premium	1,136			931			2,188			1,830
Capitalized interest	(3,190		)	(790		)	(5,428		)	(1,090		)
Net interest expense	$	12,254		$	10,228		$	23,695		$	20,824

Net interest expense increased $2 million between the quarterly periods and $2.9 million between the six month periods. In February 2013, we issued an additional $350 million of aggregate principal amount of 5.75% senior unsecured notes to repay borrowings under our senior secured credit facility. Capitalized interest costs, which increased $2.4 million and $4.3 million in the three and six month periods, respectively, due to our growth capital expenditures and 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, 2013 included an unrealized gain on derivative positions of $2 million. Net income for the same period in 2012 included an unrealized loss on derivative positions of $0.8 million. Net income for the six months ended June 30, 2013 and 2012 included an unrealized gain on derivative positions of $2 million and $1.2 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.

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Liquidity and Capital Resources

General

As of June 30, 2013, we had $666.5 million of borrowing capacity available under our $1 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuance of senior notes.

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.

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—and to implement our growth strategy successfully. No assurance can be made that we will be able to raise necessary funds on satisfactory terms.

Our $1 billion senior secured credit facility matures on July 25, 2017 and includes an accordion feature of $300 million, giving us the ability to expand the size of the facility up to an aggregate of $1.3 billion for acquisitions or internal growth projects, subject to lender consent. The inventory financing sublimit tranche under our senior secured credit facility is $150 million, which 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. Our credit facility allows up to $100 million of the capacity to be used for letters of credit, of which $14.4 million was outstanding at June 30, 2013. Due to the revolving nature of loans under our credit facility, we may make additional borrowings and periodic repayments and re-borrowings until the maturity date. At June 30, 2013, we had $319.1 million borrowed under our credit facility, with $73.4 million of the borrowed amount designated as a loan under the inventory sublimit. Thus, the total amount available for borrowings under our credit facility at June 30, 2013 was $666.5 million.

On February 8, 2013, we issued an additional $350 million of aggregate principal amount of 5.75% senior unsecured notes. The notes were sold at face value. Interest payments are due on February 15 and August 15 of each year, beginning August 15, 2013. The notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes.

The notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly-owned subsidiaries. We have the right to redeem the notes at any time after February 15, 2017, at a premium to the face amount of the notes that varies based on the time remaining to maturity on the notes. Prior to February 15, 2016, we may also redeem up to 35% of the principal amount for 105.750% of the face amount with the proceeds from an equity offering of our common units.

At June 30, 2013, long-term debt totaled $1 billion, consisting of $319.1 million outstanding under our credit facility (including $73.4 million borrowed under the inventory sublimit tranche), a $350.8 million carrying amount of senior unsecured notes due on December 15, 2018 and a $350 million carrying amount of senior unsecured notes due on February 15, 2021.

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 facility 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.

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We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. 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 crude 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.

The storage of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the crude oil or petroleum products, which negatively impacts our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, we may be required to deposit margin funds with the NYMEX when prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.

See Note 10 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, 2013 and June 30, 2012.

Net cash flows provided by our operating activities for the six months ended June 30, 2013 were $95.8 million compared to $99.3 million for the six months ended June 30, 2012. 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 petroleum products will require more or less cash. The decrease in operating cash flow for the six months ended June 30, 2013 compared to the same period in 2012 was primarily due to increases in cash requirements to meet working capital needs, partially offset by higher cash earnings.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, 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/or the issuance of senior unsecured notes.

Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, business and other asset acquisitions for the six months ended June 30, 2013 and June 30, 2012 is as follows:



	Six Months Ended June 30,
	2013		2012
	(in thousands)
Capital expenditures for fixed and intangible assets:
Pipeline transportation assets	$	55,201	$	21,322
Refinery services assets	1,664		1,270
Supply and logistics assets	56,059		63,004
Information technology systems upgrade projects	958		1,040
Total capital expenditures for fixed and intangible assets	113,882		86,636
Capital expenditures for business combinations, net of liabilities assumed:
Offshore pipelines ⁽¹⁾	—		205,576
Total business combinations capital expenditures	—		205,576
Capital expenditures related to equity investees ⁽²⁾	66,207		51,431
Total capital expenditures	$	180,089	$	343,643

(1) In 2012, amount represents the investment to acquire interests in several Gulf of Mexico crude oil pipeline systems.

(2) Amounts represent 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.

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Capital Expenditures for Acquisition

We have agreed to acquire for approximately $230 million substantially all the assets of the downstream transportation business of Hornbeck. The business is primarily comprised of nine barges and nine tug boats which transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. At the closing of the transaction, we expect to enter into transition service agreements to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. We expect to finance the acquisition with funds available under our $1 billion revolving credit facility and to complete the transaction by the end of the third quarter of 2013.

Growth Capital Expenditures

Total capital expenditures on projects currently under construction, and disclosed in the following discussion, are estimated to be approximately $580 million, inclusive of capital expenditures incurred in prior quarters. We anticipate that approximately $410 million of that total will be spent in 2013.

Gulf Coast Infrastructure

We budgeted approximately $125 million to improve existing assets and develop new infrastructure in Louisiana, including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal at Port Hudson, Louisiana, constructing a new 18-mile 20-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Maryland Terminal and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at the Maryland Terminal. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of 2013, and the Maryland Terminal completion is scheduled for the second quarter of 2014.

Texas City Project

We are constructing an 18-inch diameter loop of our existing Texas 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 in the third quarter of 2013.

HollyFrontier Tulsa Project

We are installing 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 late in the third quarter of 2013, 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.

Rail Projects

In the first quarter of 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank and related equipment. This facility is capable of handling unit train shipments of oil for direct deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other markets in the Southeast at the option of the shippers. The unit trains of crude oil received at Walnut Hill, Florida will be inserted downstream for further delivery on our Jay Pipeline System. We have commenced construction on an additional tank at the site with 110,000 barrels of capacity, which will allow us to handle increased rail traffic and higher throughput on our existing connected Jay crude oil pipeline. We estimate this tank will be fully operational in the fourth quarter of 2013.

In 2012, we completed the initial phase construction of a crude oil rail loading facility in Wink, Texas, giving us the capability to load Genesis and third party railcars designed to move crude oil from West Texas to other markets. Construction on the second phase of the facility, which we estimate will be operational in the fourth quarter of 2013, will allow us to increase the capacity of this rail loading facility.

In 2012, we commenced construction on a crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. That facility will have the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada. We believe that facility will be operational in the third quarter of 2013. We have initiated construction on the second phase of the Natchez facility, which will provide an additional 60 railcar spots and additional heated tanks, and anticipate this rail unloading/loading facility expansion to be fully operational in late 2013.

In the second quarter of 2013, we began construction on a new unit train loading facility in the Powder River Basin of the Niobrara Shale Play. The facility will be tied-in to our existing gathering system in the region and is expected to be fully operational in late 2013.

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Wyoming Gathering Project

In the second quarter of 2013, we completed the re-activation of portions of the related gathering and transportation pipelines in Wyoming and construction of a new pipeline which connects to the Casper, Wyoming markets.

Capital Expenditures Related to Equity Investees

SEKCO, a joint venture with Enterprise Products, is constructing 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 have budgeted approximately $200 million for our cumulative share of the pipeline construction through 2014 and to reimburse Enterprise Products for our portion of previously incurred costs. In 2012, we contributed $63.7 million to SEKCO that was used to fund our share of the construction costs incurred during the year. We have budgeted approximately $125 million in 2013, of which we have paid $66.2 million during the first six months of 2013. Most cost overruns and other costs incurred associated with weather-related delays will be the responsibility of the producers that have entered into transportation agreements with us.

Distributions to Unitholders

On August 14, 2013, we will pay a distribution of $0.51 per common unit totaling $42.3 million with respect to the second quarter of 2013 to common unitholders of record on August 1, 2013. This is the thirty-second consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 7 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, 2012.

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, 2012, 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, and historical performance is not necessarily indicative of future performance. 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, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;


•	throughput levels and rates;


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


•	our ability to successfully identify and 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;

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•	service interruptions in our pipeline transportation systems and processing operations;


•	shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum or other products or to whom we sell such products;


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


•	changes in laws and regulations to which we are subject, including tax withholding issues, accounting pronouncements, and 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 or counterparties;


•	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, 2012. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents 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 Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 11 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 on Form 10-Q is accumulated and 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.

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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, 2012. 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, 2012, as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

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

None.

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).

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*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Schema Document
*	101.CAL	XBRL Calculation Linkbase Document
*	101.LAB	XBRL Label Linkbase Document
*	101.PRE	XBRL Presentation Linkbase Document
*	101.DEF	XBRL Definition Linkbase Document



*	Filed herewith

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SIGNATURES

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



		GENESIS ENERGY, L.P. (A Delaware Limited Partnership)

	By:	GENESIS ENERGY, LLC, as General Partner



Date:	August 1, 2013	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer