Edgar Filing: GENESIS ENERGY LP

GEL 6.30.2014 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, 2014

¨ 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 88,650,988 Class A Common Units and 39,997 Class B Common Units outstanding as of August 5, 2014.

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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. Recent Accounting Developments	7
	3. Acquisition and Divestiture	8
	4. Inventories	9
	5. Fixed Assets and Asset Retirement Obligations	10
	6. Equity Investees	10
	7. Intangible Assets	11
	8. Debt	12
	9. Partner's Capital and Distributions	13
	10. Business Segment Information	13
	11. Transactions with Related Parties	15
	12. Supplemental Cash Flow Information	16
	13. Derivatives	16
	14. Fair-Value Measurements	19
	15. Contingencies	19
	16. Condensed Consolidating Financial Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	44
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
SIGNATURES		47

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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, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	14,326		$	8,866
Accounts receivable - trade, net	346,548			368,033
Inventories	129,852			85,330
Other	29,045			72,994
Total current assets	519,771			535,223
FIXED ASSETS, at cost	1,552,110			1,327,974
Less: Accumulated depreciation	(227,838		)	(199,230		)
Net fixed assets	1,324,272			1,128,744
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	148,854			151,903
EQUITY INVESTEES	620,188			620,247
INTANGIBLE ASSETS, net of amortization	56,993			62,928
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	48,005			38,111
TOTAL ASSETS	$	3,043,129		$	2,862,202
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	316,999		$	316,204
Accrued liabilities	95,281			130,349
Total current liabilities	412,280			446,553
SENIOR SECURED CREDIT FACILITY	492,200			582,800
SENIOR UNSECURED NOTES	1,050,707			700,772
DEFERRED TAX LIABILITIES	16,797			15,944
OTHER LONG-TERM LIABILITIES	18,721			18,396
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 88,690,985 units issued and outstanding at June 30, 2014 and December 31, 2013, respectively	1,052,424			1,097,737
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	3,043,129		$	2,862,202

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,
	2014			2013			2014			2013
REVENUES:
Supply and logistics	$	939,056		$	994,681		$	1,883,662		$	1,939,226
Refinery services	52,801			51,476			106,994			100,960
Pipeline transportation services	23,192			22,537			44,112			43,316
Total revenues	1,015,049			1,068,694			2,034,768			2,083,502
COSTS AND EXPENSES:
Supply and logistics product costs	844,395			922,711			1,693,657			1,792,555
Supply and logistics operating costs	64,679			45,849			127,771			94,621
Refinery services operating costs	31,148			32,821			64,343			65,264
Pipeline transportation operating costs	8,383			7,145			15,861			14,229
General and administrative	14,696			11,142			26,706			22,753
Depreciation and amortization	20,491			15,665			39,771			30,714
Total costs and expenses	983,792			1,035,333			1,968,109			2,020,136
OPERATING INCOME	31,257			33,361			66,659			63,366
Equity in earnings of equity investees	4,922			5,623			12,740			9,559
Interest expense	(14,069		)	(12,255		)	(26,873		)	(23,696		)
Income from continuing operations before income taxes	22,110			26,729			52,526			49,229
Income tax (expense) benefit	(962		)	(117		)	(1,603		)	86
Income from continuing operations	21,148			26,612			50,923			49,315
Income from discontinued operations	—			290			—			433
NET INCOME	$	21,148		$	26,902		$	50,923		$	49,748
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
Continuing operations	$	0.24		$	0.32		$	0.57		$	0.60
Discontinued operations	—			0.01			—			0.01
Net income per common unit	$	0.24		$	0.33		$	0.57		$	0.61
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	88,691			81,973			88,691			81,590

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
	2014	2013	2014			2013
Partners’ capital, January 1	88,691	81,203	$	1,097,737		$	916,495
Net income	—	—	50,923			49,748
Cash distributions	—	—	(96,236		)	(79,795		)
Conversion of waiver units	—	1,738	—			—
Partners' capital, June 30	88,691	82,941	$	1,052,424		$	886,448

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,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	50,923		$	49,748
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	39,771			30,723
Amortization of debt issuance costs and premium	2,320			2,128
Amortization of unearned income and initial direct costs on direct financing leases	(7,922		)	(8,136		)
Payments received under direct financing leases	10,631			10,631
Equity in earnings of investments in equity investees	(12,740		)	(9,559		)
Cash distributions of earnings of equity investees	21,452			15,475
Non-cash effect of equity-based compensation plans	6,267			8,710
Deferred and other tax liabilities (benefits)	853			(536		)
Unrealized gains on derivative transactions	(1,187		)	(2,023		)
Other, net	1,518			93
Net changes in components of operating assets and liabilities (Note 12)	(6,689		)	(1,468		)
Net cash provided by operating activities	105,197			95,786
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(240,994		)	(107,166		)
Cash distributions received from equity investees - return of investment	6,173			5,539
Investments in equity investees	(14,826		)	(66,207		)
Proceeds from asset sales	133			626
Other, net	(2,635		)	171
Net cash used in investing activities	(252,149		)	(167,037		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,181,200			668,500
Repayments on senior secured credit facility	(1,271,800		)	(849,400		)
Proceeds from issuance of senior unsecured notes	350,000			350,000
Debt issuance costs	(10,752		)	(8,157		)
Distributions to common unitholders	(96,236		)	(79,795		)
Other, net	—			(2,511		)
Net cash provided by financing activities	152,412			78,637
Net increase in cash and cash equivalents	5,460			7,386
Cash and cash equivalents at beginning of period	8,866			11,282
Cash and cash equivalents at end of period	$	14,326		$	18,668

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, Wyoming 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, 2013.

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

2. Recent Accounting Developments

Recently Issued

In May 2014, the Financial Accounting Standards Board ("FASB") issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance will be effective for us beginning January 1, 2017 and early adoption is not permitted. The guidance permits the use of either a full retrospective or a modified retrospective approach. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

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3. Acquisition and Divestiture

Acquisition

Offshore Marine Transportation Business

In August 2013, we completed the acquisition of substantially all of the assets of the downstream transportation business of Hornbeck Offshore Services, Inc. for $230.9 million, which we refer to as our offshore marine transportation business and assets. The total acquisition cost has been allocated to fixed assets based on fair values. Such fair values were developed by management. The acquired business was 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. That acquisition complements and further integrates our existing operations, including our Genesis Marine inland barge business (comprised of 60 barges and 23 push/tow boats), our crude oil and heavy refined products storage and blending terminals as well as our crude oil pipeline systems. That acquisition was funded with proceeds from our $1 billion revolving credit facility. We have reflected the financial results of the acquired business in our supply and logistics segment from the date of the acquisition.

The following table presents selected unaudited financial information of our offshore marine transportation business included in our Unaudited Condensed Consolidated Statement of Operations for the periods presented:



	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
Revenues	$	23,591	$	48,475
Net income	$	6,293	$	12,824

The table below presents selected unaudited pro forma financial information incorporating the historical results of our offshore marine transportation business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2012 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. Depreciation expense for the fixed assets acquired is calculated on a straight-line basis over an estimated useful life of approximately 25 years.



	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013
Pro forma earnings data:
Revenues	$	1,085,206	$	2,115,004
Net income	$	31,351	$	57,486

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Divestiture

On December 31, 2013, we completed the sale of our vehicle fuel procurement and delivery logistics management services business. That business, previously reported in our supply and logistics revenues and costs and expenses, was reclassified as discontinued operations in our Unaudited Condensed Consolidated Statements of Operations for the quarter and six months ended June 30, 2013. The summarized operating results of our discontinued operations are as follows:



	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013
Revenues	$	144,962	$	277,368
Cost and expenses	144,672		276,936
Operating income	290		432
Interest income	—		1
Income from discontinued operations	$	290	$	433

4. Inventories

The major components of inventories were as follows:



	June 30, 2014		December 31, 2013
Petroleum products	$	99,242	$	71,373
Crude oil	21,093		5,380
Caustic soda	3,536		2,679
NaHS	5,978		5,845
Other	3		53
Total	$	129,852	$	85,330

Inventories are valued at the lower of cost or market. At June 30, 2014 and December 31, 2013, market values of our inventories exceeded recorded costs.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	June 30, 2014			December 31, 2013
Pipelines and related assets	$	421,319		$	338,920
Machinery and equipment	260,457			173,092
Transportation equipment	18,535			19,140
Marine vessels	585,933			554,679
Land, buildings and improvements	31,912			30,170
Office equipment, furniture and fixtures	5,537			5,633
Construction in progress	195,712			183,037
Other	32,705			23,303
Fixed assets, at cost	1,552,110			1,327,974
Less: Accumulated depreciation	(227,838		)	(199,230		)
Net fixed assets	$	1,324,272		$	1,128,744

Our depreciation expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Depreciation expense	$	16,409	$	11,067	$	31,686	$	21,558

6. 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, 2014 and December 31, 2013, the unamortized excess cost amounts totaled $220.6 million and $225.7 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,
	2014			2013			2014			2013
Genesis’ share of operating earnings	$	7,505		$	8,221		$	17,906		$	14,871
Amortization of excess purchase price	(2,583		)	(2,598		)	(5,166		)	(5,312		)
Net equity in earnings	$	4,922		$	5,623		$	12,740		$	9,559
Distributions received	$	15,045		$	11,384		$	27,625		$	21,014

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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, 2014		December 31, 2013
BALANCE SHEET DATA:
Assets
Current assets	$	77,714	$	70,921
Fixed assets, net	1,034,909		1,028,808
Other assets	6,594		6,823
Total assets	$	1,119,217	$	1,106,552
Liabilities and equity
Current liabilities	$	71,745	$	55,918
Other liabilities	198,596		190,578
Equity	848,876		860,056
Total liabilities and equity	$	1,119,217	$	1,106,552



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
INCOME STATEMENT DATA:
Revenues	$	46,440	$	45,528	$	96,264	$	86,268
Operating income	$	22,628	$	26,427	$	53,103	$	47,527
Net income	$	21,815	$	25,748	$	51,521	$	46,203

7. Intangible Assets

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



	June 30, 2014						December 31, 2013
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	79,082	$	15,572	$	94,654	$	76,283	$	18,371
Licensing agreements	38,678		27,519		11,159		38,678		26,055		12,623
Segment total	133,332		106,601		26,731		133,332		102,338		30,994
Supply & Logistics:
Customer relationships	35,430		29,398		6,032		35,430		28,568		6,862
Intangibles associated with lease	13,260		3,275		9,985		13,260		3,039		10,221
Segment total	48,690		32,673		16,017		48,690		31,607		17,083
Other	21,714		7,469		14,245		21,356		6,505		14,851
Total	$	203,736	$	146,743	$	56,993	$	203,378	$	140,450	$	62,928

Our amortization expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Amortization expense	$	3,147	$	3,609	$	6,292	$	7,236

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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	2014	$	6,317
	2015	$	10,814
	2016	$	9,352
	2017	$	8,189
	2018	$	7,268

8. Debt

Our obligations under debt arrangements consisted of the following:



	June 30, 2014		December 31, 2013
Senior secured credit facility	$	492,200	$	582,800
7.875% senior unsecured notes (including unamortized premium of $707 and $772 in 2014 and 2013, respectively)	350,707		350,772
5.750% senior unsecured notes	350,000		350,000
5.625% senior unsecured notes	350,000		—
Total long-term debt	$	1,542,907	$	1,283,572

As of June 30, 2014, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Senior Secured Credit Facility

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

•The applicable margin varies from 1.50% to 2.50% on Eurodollar borrowings and from 0.50% to 1.50% on alternate base rate borrowings.

•Letter of credit fees range from 1.50% to 2.50%

•The commitment fee on the unused committed amount will range from 0.250% to 0.375%.

At June 30, 2014, we had $492.2 million borrowed under our $1 billion credit facility, with $105.9 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 $19.9 million was outstanding at June 30, 2014. 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, 2014 was $487.9 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 additional 2018 Notes have the same terms and conditions as the notes previously issued under their indenture. The issuance increased the total aggregate principal amount of the 2018 Notes under their indenture to $350 million.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On February 8, 2013, we issued $350 million in 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. 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.

On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes (the "2024 Notes"). The 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. The 2024 Notes mature on June 15, 2024.

The 2018, 2021 and 2024 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. 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. We have the right to redeem the 2024 Notes at any time after June 15, 2019, at a premium to the face amount of the 2024 Notes that varies based on the time remaining to maturity on the 2024 Notes. Prior to June 15, 2017, we may also redeem up to 35% of the principal amount of the 2024 Notes for 105.625% of the face amount with the proceeds from an equity offering of our common units.

9. Partners’ Capital and Distributions

At June 30, 2014, our outstanding common units consisted of 88,650,988 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 were/are convertible into Class A common units at a 1:1 conversion rate in the calendar quarter 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 $0.52 for our Class 4 waiver units.

Our Class 1 and Class 2 waiver units converted into common units in 2012 and our Class 3 waiver units were converted into common units in 2013.

At June 30, 2014, we had 1,738,233 waiver units outstanding comprised of the Class 4 waiver units. The Class 4 waiver units will convert into common units when we satisfy the distribution conversion ratio requirement and pay a minimum distribution of $0.52 per common unit.

Distributions

We paid or will pay the following distributions in 2013 and 2014:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2013
1^st Quarter	May 15, 2013		$	0.4975	$	40,405
2^nd Quarter	August 14, 2013		$	0.5100	$	42,302
3^rd Quarter	November 14, 2013		$	0.5225	$	46,344
4^th Quarter	February 14, 2014		$	0.5350	$	47,453
2014
1^st Quarter	May 15, 2014		$	0.5500	$	48,783
2^nd Quarter	August 14, 2014	⁽¹⁾	$	0.5650	$	50,114

(1) This distribution will be paid to unitholders of record as of August 1, 2014.

10. Business Segment Information

Our operations consist of three operating segments:


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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


•	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.

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 legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases.

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment.

Segment information for the periods presented below was as follows:



	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended June 30, 2014
Segment margin (a)	$	27,966	$	21,627		$	33,088		$	82,681
Capital expenditures (b)	$	7,037	$	597		$	132,490		$	140,124
Revenues:
External customers	$	19,758	$	55,552		$	939,739		$	1,015,049
Intersegment (c)	3,434		(2,751		)	(683		)	—
Total revenues of reportable segments	$	23,192	$	52,801		$	939,056		$	1,015,049
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		$	995,226		$	1,068,694
Intersegment (c)	3,357		(2,812		)	(545		)	—
Total revenues of reportable segments	$	22,537	$	51,476		$	994,681		$	1,068,694
Six Months Ended June 30, 2014
Segment Margin (a)	$	56,058	$	42,499		$	61,475		$	160,032
Capital expenditures (b)	$	41,317	$	899		$	200,686		$	242,902
Revenues:
External customers	$	36,208	$	112,659		$	1,885,901		$	2,034,768
Intersegment (c)	7,904		(5,665		)	(2,239		)	—
Total revenues of reportable segments	$	44,112	$	106,994		$	1,883,662		$	2,034,768
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		$	1,940,550		$	2,083,502
Intersegment (c)	6,831		(5,507		)	(1,324		)	—
Total revenues of reportable segments	$	43,316	$	100,960		$	1,939,226		$	2,083,502

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Total assets by reportable segment were as follows:



	June 30, 2014		December 31, 2013
Pipeline transportation	$	1,092,842	$	1,075,235
Refinery services	408,304		417,121
Supply and logistics	1,472,703		1,312,461
Other assets	69,280		57,385
Total consolidated assets	$	3,043,129	$	2,862,202


(a)	A reconciliation of Segment Margin to income from continuing operations for the periods presented is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Segment Margin	$	82,681		$	70,442		$	160,032		$	142,507
Corporate general and administrative expenses	(13,789		)	(10,305		)	(24,850		)	(21,142		)
Depreciation and amortization	(20,491		)	(15,665		)	(39,771		)	(30,714		)
Interest expense	(14,069		)	(12,255		)	(26,873		)	(23,696		)
Distributable cash from equity investees in excess of equity in earnings	(7,808		)	(4,891		)	(13,585		)	(11,455		)
Non-cash items not included in Segment Margin	(3,043		)	960			282			(3,335		)
Cash payments from direct financing leases in excess of earnings	(1,371		)	(1,263		)	(2,709		)	(2,495		)
Income tax (expense) benefit	(962		)	(117		)	(1,603		)	86
Discontinued operations	—			(294		)	—			(441		)
Income from continuing operations	$	21,148		$	26,612		$	50,923		$	49,315

(b)

Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and interests in equity investees. In addition to construction of growth projects, capital spending in our pipeline transportation segment included $2.3 million and $12.7 million during the three and six months ended June 30, 2014 and $1.7 million and $66.2 million three and six months ended June 30, 2013 representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline.


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

11. 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,
	2014		2013		2014		2013
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	713	$	808	$	1,368	$	1,481
Petroleum products sales to Davison family businesses⁽²⁾	—		289		—		644
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	150	$	150	$	300	$	300


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


(2)	Amounts included in discontinued operations for all periods presented.

Amount due from Related Party

At June 30, 2014 and December 31, 2013 Sandhill Group, LLC owed us $0.3 million and $0.2 million, respectively, for purchases of CO₂.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. 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,
	2014			2013
(Increase) decrease in:
Accounts receivable	$	20,827		$	(82,346	)
Inventories	(44,523		)	(858		)
Other current assets	47,542			11,135
Increase (decrease) in:
Accounts payable	13,436			66,860
Accrued liabilities	(43,971		)	3,741
Net changes in components of operating assets and liabilities	$	(6,689	)	$	(1,468	)

Payments of interest and commitment fees were $33.4 million and $18.9 million for the six months ended June 30, 2014 and June 30, 2013, respectively.

At June 30, 2014 and June 30, 2013, we had incurred liabilities for fixed and intangible asset additions totaling $42.1 million and $20.8 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, 2014 and June 30, 2013, we had incurred liabilities for other asset additions totaling $0.1 million and $0.2 million, respectively, 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.

13. 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2014, 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.



	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	613		132
Weighted average contract price per bbl	$	104.52	$	105.70
Diesel futures:
Contract volumes (1,000 bbls)	122		2
Weighted average contract price per gal	$	2.98	$	3.04
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	470		—
Weighted average contract price per bbl	$	91.25	$	—
Crude oil options:
Contract volumes (1,000 bbls)	155		—
Weighted average premium received	$	0.97	$	—
Diesel options:
Contract volumes (1,000 bbls)	25		—
Weighted average premium received	$	2.58	$	—

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, 2014 and December 31, 2013:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	June 30, 2014			December 31, 2013
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	344		$	615
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(344		)	(615		)
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⁾	$	(2,553	)	$	(4,527	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	2,553			4,527
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, 2014, we had a net broker receivable of approximately $3.5 million (consisting of initial margin of $2.9 million increased by $0.6 million of variation margin). As of December 31, 2013, we had a net broker receivable of approximately $5.3 million (consisting of initial margin of $4.1 million increased by $1.2 million of variation margin). At June 30, 2014 and December 31, 2013, 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,
		2014		2013		2014		2013
Commodity derivatives - futures and call options:
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	$	727	$	5,148	$	3,496	$	1,645
Total commodity derivatives		$	727	$	5,148	$	3,496	$	1,645

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. 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 as of June 30, 2014 and December 31, 2013.



	Fair Value at							Fair Value at
	June 30, 2014							December 31, 2013
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	344		$	—	$	—	$	615		$	—	$	—
Liabilities	$	(2,553	)	$	—	$	—	$	(4,527	)	$	—	$	—

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 13 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, 2014, our senior unsecured notes had a carrying value of $1.1 billion and a fair value of $1.1 billion, compared to $0.7 billion and $0.7 billion, respectively, at December 31, 2013. 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.

15. 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16. Condensed Consolidating Financial Information

Our $1.05 billion 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 current and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 8 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, 2014



	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	$	—	$	13,295		$	1,021		$	—		$	14,326
Other current assets	1,369,932		—		476,342			58,779			(1,399,608		)	505,445
Total current assets	1,369,942		—		489,637			59,800			(1,399,608		)	519,771
Fixed assets, at cost	—		—		1,434,885			117,225			—			1,552,110
Less: Accumulated depreciation	—		—		(207,927		)	(19,911		)	—			(227,838		)
Net fixed assets	—		—		1,226,958			97,314			—			1,324,272
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	19,047		—		241,932			149,624			(156,751		)	253,852
Equity investees	—		—		620,188			—			—			620,188
Investments in subsidiaries	1,217,721		—		127,397			—			(1,345,118		)	—
Total assets	$	2,606,710	$	—	$	3,031,158		$	306,738		$	(2,901,477	)	$	3,043,129
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	11,379	$	—	$	1,780,446		$	20,217		$	(1,399,762	)	$	412,280
Senior secured credit facility	492,200		—		—			—			—			492,200
Senior unsecured notes	1,050,707		—		—			—			—			1,050,707
Deferred tax liabilities	—		—		16,797			—			—			16,797
Other liabilities	—		—		15,028			160,271			(156,578		)	18,721
Total liabilities	1,554,286		—		1,812,271			180,488			(1,556,340		)	1,990,705
Partners’ capital	1,052,424		—		1,218,887			126,250			(1,345,137		)	1,052,424
Total liabilities and partners’ capital	$	2,606,710	$	—	$	3,031,158		$	306,738		$	(2,901,477	)	$	3,043,129

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 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	$	20	$	—	$	8,061		$	785		$	—		$	8,866
Other current assets	1,133,695		—		498,230			54,199			(1,159,767		)	526,357
Total current assets	1,133,715		—		506,291			54,984			(1,159,767		)	535,223
Fixed assets, at cost	—		—		1,211,356			116,618			—			1,327,974
Less: Accumulated depreciation	—		—		(181,905		)	(17,325		)	—			(199,230		)
Net fixed assets	—		—		1,029,451			99,293			—			1,128,744
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	21,432		—		238,282			152,413			(159,185		)	252,942
Equity investees	—		—		620,247			—			—			620,247
Investments in subsidiaries	1,236,164		—		124,718			—			(1,360,882		)	—
Total assets	$	2,391,311	$	—	$	2,844,035		$	306,690		$	(2,679,834	)	$	2,862,202
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	10,002	$	—	$	1,576,186		$	19,660		$	(1,159,295	)	$	446,553
Senior secured credit facility	582,800		—		—			—			—			582,800
Senior unsecured notes	700,772		—		—			—			—			700,772
Deferred tax liabilities	—		—		15,944			—			—			15,944
Other liabilities	—		—		14,664			162,739			(159,007		)	18,396
Total liabilities	1,293,574		—		1,606,794			182,399			(1,318,302		)	1,764,465
Partners’ capital	1,097,737		—		1,237,241			124,291			(1,361,532		)	1,097,737
Total liabilities and partners’ capital	$	2,391,311	$	—	$	2,844,035		$	306,690		$	(2,679,834	)	$	2,862,202

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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, 2014



	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	$	—		$	—	$	936,331		$	30,551		$	(27,826	)	$	939,056
Refinery services	—			—		51,694			4,571			(3,464		)	52,801
Pipeline transportation services	—			—		16,684			6,508			—			23,192
Total revenues	—			—		1,004,709			41,630			(31,290		)	1,015,049
COSTS AND EXPENSES:
Supply and logistics costs	—			—		906,860			30,042			(27,828		)	909,074
Refinery services operating costs	—			—		30,399			4,212			(3,463		)	31,148
Pipeline transportation operating costs	—			—		7,903			480			—			8,383
General and administrative	—			—		14,666			30			—			14,696
Depreciation and amortization	—			—		19,181			1,310			—			20,491
Total costs and expenses	—			—		979,009			36,074			(31,291		)	983,792
OPERATING INCOME	—			—		25,700			5,556			1			31,257
Equity in earnings of subsidiaries	35,214			—		1,595			—			(36,809		)	—
Equity in earnings of equity investees	—			—		4,922			—			—			4,922
Interest (expense) income, net	(14,066		)	—		3,932			(3,935		)	—			(14,069		)
Income from continuing operations before income taxes	21,148			—		36,149			1,621			(36,808		)	22,110
Income tax expense	—			—		(890		)	(72		)	—			(962		)
Income from continuing operations	21,148			—		35,259			1,549			(36,808		)	21,148
Income from discontinued operations	—			—		—			—			—			—
NET INCOME	$	21,148		$	—	$	35,259		$	1,549		$	(36,808	)	$	21,148

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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	$	—		$	—	$	989,591		$	35,124		$	(30,034	)	$	994,681
Refinery services	—			—		51,682			3,796			(4,002		)	51,476
Pipeline transportation services	—			—		15,731			6,806			—			22,537
Total revenues	—			—		1,057,004			45,726			(34,036		)	1,068,694
COSTS AND EXPENSES:
Supply and logistics costs	—			—		965,373			33,221			(30,034		)	968,560
Refinery services operating costs	—			—		32,915			3,516			(3,610		)	32,821
Pipeline transportation operating costs	—			—		6,668			477			—			7,145
General and administrative	—			—		11,115			27			—			11,142
Depreciation and amortization	—			—		14,755			910			—			15,665
Total costs and expenses	—			—		1,030,826			38,151			(33,644		)	1,035,333
OPERATING INCOME	—			—		26,178			7,575			(392		)	33,361
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		)	—		4,029			(4,053		)	—			(12,255		)
Income from continuing operations before income taxes	26,902			—		39,363			3,522			(43,058		)	26,729
Income tax expense	—			—		(87		)	(30		)	—			(117		)
Income from continuing operations	26,902			—		39,276			3,492			(43,058		)	26,612
Income from discontinued operations	—			—		290			—			—			290
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

Six Months Ended June 30, 2014



	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	$	—		$	—	$	1,878,368		$	62,762		$	(57,468	)	$	1,883,662
Refinery services	—			—		103,424			10,645			(7,075		)	106,994
Pipeline transportation services	—			—		31,291			12,821			—			44,112
Total revenues	—			—		2,013,083			86,228			(64,543		)	2,034,768
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,817,980			60,916			(57,468		)	1,821,428
Refinery services operating costs	—			—		61,990			10,058			(7,705		)	64,343
Pipeline transportation operating costs	—			—		14,958			903			—			15,861
General and administrative	—			—		26,646			60			—			26,706
Depreciation and amortization	—			—		37,176			2,595			—			39,771
Total costs and expenses	—			—		1,958,750			74,532			(65,173		)	1,968,109
OPERATING INCOME	—			—		54,333			11,696			630			66,659
Equity in earnings of subsidiaries	77,793			—		3,759			—			(81,552		)	—
Equity in earnings of equity investees	—			—		12,740			—			—			12,740
Interest (expense) income, net	(26,870		)	—		7,898			(7,901		)	—			(26,873		)
Income from continuing operations before income taxes	50,923			—		78,730			3,795			(80,922		)	52,526
Income tax expense	—			—		(1,477		)	(126		)	—			(1,603		)
Income from continuing operations	50,923			—		77,253			3,669			(80,922		)	50,923
Income from discontinued operations	—			—		—			—			—			—
NET INCOME	$	50,923		$	—	$	77,253		$	3,669		$	(80,922	)	$	50,923

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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	$	—		$	—	$	1,927,674	$	74,069		$	(62,517	)	$	1,939,226
Refinery services	—			—		99,449		9,359			(7,848		)	100,960
Pipeline transportation services	—			—		29,857		13,459			—			43,316
Total revenues	—			—		2,056,980		96,887			(70,365		)	2,083,502
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,882,181		67,512			(62,517		)	1,887,176
Refinery services operating costs	—			—		64,082		8,798			(7,616		)	65,264
Pipeline transportation operating costs	—			—		13,422		807			—			14,229
General and administrative	—			—		22,693		60			—			22,753
Depreciation and amortization	—			—		28,902		1,812			—			30,714
Total costs and expenses	—			—		2,011,280		78,989			(70,133		)	2,020,136
OPERATING INCOME	—			—		45,700		17,898			(232		)	63,366
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		)	—		8,076		(8,135		)	—			(23,696		)
Income from continuing operations before income taxes	49,748			—		73,106		9,763			(83,388		)	49,229
Income tax benefit (expense)	—			—		170		(84		)	—			86
Income from continuing operations	49,748			—		73,276		9,679			(83,388		)	49,315
Income from discontinued operations	—			—		433		—			—			433
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 Cash Flows

Six Months Ended June 30, 2014



	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	$	(175,807	)	$	—	$	350,596		$	5,007		$	(74,599	)	$	105,197
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(240,385		)	(609		)	—			(240,994		)
Cash distributions received from equity investees - return of investment	23,385			—		6,173			—			(23,385		)	6,173
Investments in equity investees	—			—		(14,826		)	—			—			(14,826		)
Repayments on loan to non-guarantor subsidiary	—			—		2,433			—			(2,433		)	—
Proceeds from asset sales	—			—		133			—			—			133
Other, net	—			—		(2,635		)	—			—			(2,635		)
Net cash provided by (used) in investing activities	23,385			—		(249,107		)	(609		)	(25,818		)	(252,149		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,181,200			—		—			—			—			1,181,200
Repayments on senior secured credit facility	(1,271,800		)	—		—			—			—			(1,271,800		)
Proceeds from issuance of senior unsecured notes	350,000			—		—			—			—			350,000
Debt issuance costs	(10,752		)	—		—			—			—			(10,752		)
Distributions to partners/owners	(96,236		)	—		(96,236		)	(1,768		)	98,004			(96,236		)
Other, net	—			—		(19		)	(2,394		)	2,413			—
Net cash provided by (used in) financing activities	152,412			—		(96,255		)	(4,162		)	100,417			152,412
Net (decrease) increase in cash and cash equivalents	(10		)	—		5,234			236			—			5,460
Cash and cash equivalents at beginning of period	20			—		8,061			785			—			8,866
Cash and cash equivalents at end of period	$	10		$	—	$	13,295		$	1,021		$	—		$	14,326

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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 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	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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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, 2013.

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 $21.1 million, or $0.24 per common unit during the three months ended June 30, 2014 (“2014 Quarter”) compared to net income of $26.9 million or $0.33 per common unit during the three months ended June 30, 2013 (“2013 Quarter”).

Available Cash before Reserves increased $9.8 million, or 21%, in the 2014 Quarter (as compared to the 2013 Quarter) to $55.5 million. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin (as described below in “Financial Measures”) increased by $12.2 million, or 17%, in the 2014 Quarter, as compared to the 2013 Quarter.

The significant factor benefiting net income, Available Cash before Reserves and Segment Margin was improved operating results from each of our segments. The increase in our Segment Margin resulted primarily from increases attributable to our pipeline transportation, refinery services and supply and logistics segments of 6%, 16% and 31%, respectively.

More than offsetting the above factors benefiting net income were increases in depreciation and amortization expenses as a result of the effect of newly acquired and constructed assets in the 2014 Quarter as compared to the 2013 Quarter as well as the change in unrealized losses on derivative transactions in the 2014 Quarter as compared to unrealized gains on derivative transactions during the 2013 Quarter.

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

Distribution Increase

In July 2014, we declared our thirty-sixth consecutive increase in our quarterly distribution to our common unitholders. Thirty-one of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In August 2014, we will pay a distribution of $0.565 per unit representing a 10.8% increase from our distribution of $0.51 per unit related to the second quarter of 2013.

Financial Measures

Segment Margin

We define Segment Margin, 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, 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 legacy 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 from continuing operations is included in our segment disclosures in Note 10 to our Unaudited Condensed Consolidated Financial Statements. 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.

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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 GAAP. The accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure – income from continuing operations. 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. Among other things, 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 income from continuing operations 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 utilized. Maintenance capital is capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Our quarterly maintenance capital utilized is intended to represent the amount of cash reserves we believe is prudent to establish each quarter attributable to maintenance capital requirements in connection with determining the amount of distributable or discretionary cash flow attributable to that quarter, which cash flow we refer to as Available Cash before Reserves. We believe the most useful quarterly maintenance capital utilized amount is that portion of the amount of previously incurred maintenance capital expenditures that we realize and/or utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components. Because we have not historically used maintenance capital utilized, our future maintenance capital utilized calculations will reflect the realization and/or utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

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



	Three Months Ended June 30,
	2014			2013
	(in thousands)
Income from continuing operations	$	21,148		$	26,612
Depreciation and amortization	20,491			15,665
Cash received from direct financing leases not included in income	1,371			1,263
Cash effects of sales of certain assets	61			294
Effects of distributable cash generated by equity method investees not included in income	7,808			4,891
Cash effects of legacy stock appreciation rights plan	(127		)	(1,896		)
Non-cash legacy stock appreciation rights plan expense	322			705
Expenses related to acquiring or constructing growth capital assets	418			667
Unrealized loss (gain) on derivative transactions excluding fair value hedges	2,724			(1,971		)
Maintenance capital utilized	(178		)	(1,015		)
Non-cash tax expense (benefit)	512			(213		)
Other items, net	942			707
Available Cash before Reserves	$	55,492		$	45,709

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2014 Quarter decreased $53.6 million, or 5% from the 2013 Quarter. Additionally, our costs and expenses decreased $51.5 million, or 5% between the two periods.

The substantial majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant decrease in our revenues and costs between the two second quarter periods is primarily attributable to decreased volumes from our continuing operations relating to our supply and logistics segment, partially offset by an increase in market prices for crude oil and petroleum products as described below.

Volumes from continuing operations decreased in our supply and logistics segment by 9% quarter to quarter and 3% between the six month periods principally related to the transitioning of the operations of our refined products business in order to operate within current market conditions. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 9% to $103.00 per barrel in the second quarter of 2014, as compared to $94.22 per barrel in the second quarter of 2013.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2014 and June 30, 2013 was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Pipeline transportation	$	27,966	$	26,456	$	56,058	$	51,652
Refinery services	21,627		18,696		42,499		36,661
Supply and logistics	33,088		25,290		61,475		54,194
Total Segment Margin	$	82,681	$	70,442	$	160,032	$	142,507

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A reconciliation of Segment Margin to income from continuing operations for the periods presented is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Segment Margin	$	82,681		$	70,442		$	160,032		$	142,507
Corporate general and administrative expenses	(13,789		)	(10,305		)	(24,850		)	(21,142		)
Depreciation and amortization	(20,491		)	(15,665		)	(39,771		)	(30,714		)
Interest expense	(14,069		)	(12,255		)	(26,873		)	(23,696		)
Distributable cash from equity investees in excess of equity in earnings	(7,808		)	(4,891		)	(13,585		)	(11,455		)
Non-cash items not included in Segment Margin	(3,043		)	960			282			(3,335		)
Cash payments from direct financing leases in excess of earnings	(1,371		)	(1,263		)	(2,709		)	(2,495		)
Income tax (expense) benefit	(962		)	(117		)	(1,603		)	86
Discontinued operations	—			(294		)	—			(441		)
Income from continuing operations	$	21,148		$	26,612		$	50,923		$	49,315

Our reconciliation of Segment Margin to income from continuing operations reflects that Segment Margin (as defined above) excludes corporate general and administrative expenses, depreciation and amortization, interest expense, certain non-cash items, the most significant of which are the non-cash effects of our stock appreciation rights plan and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Items in Segment Margin not included in income from continuing operations are distributable cash from equity investees in excess of equity in earnings (or losses) and cash payments from direct financing leases in excess of earnings.

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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,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Crude oil tariffs and revenues - onshore crude oil pipelines	$	10,643		$	9,923		$	20,888		$	19,404
Segment Margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees	11,435			9,688			24,838			19,713
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	6,367			6,930			12,874			13,754
Sales of onshore crude oil pipeline loss allowance volumes	3,645			3,419			4,855			5,642
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(5,777		)	(4,997		)	(10,647		)	(9,865		)
Payments received under direct financing leases not included in income	1,371			1,263			2,709			2,495
Other	282			230			541			509
Segment Margin	$	27,966		$	26,456		$	56,058		$	51,652

Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	60,662			54,929			54,769			54,175
Jay	24,337			38,062			26,085			33,107
Mississippi	15,121			18,946			15,150			18,965
Louisiana ⁽¹⁾	22,435			—			13,574			—
Onshore crude oil pipelines total	122,555			111,937			109,578			106,247

Offshore crude oil pipelines:
CHOPS⁽²⁾	169,371			126,819			180,288			120,531
Poseidon ⁽²⁾	201,190			220,687			206,074			212,663
Odyssey ⁽²⁾	40,492			44,493			42,735			43,837
GOPL	4,197			9,335			5,814			9,132
Offshore crude oil pipelines total	415,250			401,334			434,911			386,163

CO₂ pipeline (Mcf/day):
Free State	178,500			227,168			185,010			217,844

(1) Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.

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

Three Months Ended June 30, 2014 Compared with Three Months Ended June 30, 2013

Pipeline transportation Segment Margin for the 2014 Quarter increased $1.5 million, or 6%. The significant components and details of this change were as follows:


•	Segment Margin from our offshore crude oil pipelines increased $1.7 million, primarily as a result of higher volumes transported in our offshore pipelines as a result of additional wells being connected to the pipeline in the existing fields that they service.

•

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Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm which was operational for the entirety of the 2014 Quarter. The increased crude oil tariff revenues were substantially offset by the increase in onshore crude oil pipeline operating costs also associated with the higher throughput volumes and related activity on our new Louisiana pipeline system.

•

Although volumes on our Free State CO₂ pipeline system decreased 48,668 Mcf per day, or 21%, in the 2014 Quarter as compared to the 2013 Quarter, that decrease did not materially affect contributions to Segment Margin by that pipeline. 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, fluctuations in volumes on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Six Months Ended June 30, 2014 Compared with Six Months Ended June 30, 2013

Pipeline transportation Segment Margin for the six month periods increased $4.4 million, or 9%. The significant components and details of this change were as follows:


•	Segment Margin from our offshore crude oil pipelines increased $5.1 million, primarily as a result of higher volumes transported in our offshore pipelines as a result of additional wells being connected to the pipeline in the existing fields that they service.

•

Crude oil tariff revenues of onshore crude oil pipelines increased primarily due to upward tariff indexing of approximately 4.6% for our FERC-regulated pipelines effective in July 2013. In addition, increases in crude oil tariff revenues were also a result of higher throughput volumes, including those from our Louisiana pipeline system, a new 18-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm which became operational during the latter part of the first quarter of 2014. The increased crude oil tariff revenues were substantially offset by the increase in onshore crude oil pipeline operating costs also associated with the higher throughput volumes and related activity on our new Louisiana pipeline system.

•

Although volumes on our Free State CO₂ pipeline system decreased 32,834 Mcf per day, or 15%, in the first six months of 2014 as compared to the first six months of 2013, that decrease did not materially affect contributions to Segment Margin by that pipeline. 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, fluctuations 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,
	2014			2013			2014			2013
Volumes sold (in Dry short tons "DST"):
NaHS volumes	37,607			36,665			78,509			73,287
NaOH (caustic soda) volumes	24,066			21,720			48,099			40,950
Total	61,673			58,385			126,608			114,237

Revenues (in thousands):
NaHS revenues	$	41,162		$	40,462		$	84,270		$	79,297
NaOH (caustic soda) revenues	12,642			12,695			24,787			24,097
Other revenues	1,748			1,131			3,602			3,073
Total external segment revenues	$	55,552		$	54,288		$	112,659		$	106,467

Segment Margin (in thousands)	$	21,627		$	18,696		$	42,499		$	36,661

Average index price for NaOH per DST ⁽¹⁾	$	595		$	626		$	587		$	614
Raw material and processing costs as % of segment revenues	42		%	49		%	43		%	49		%

(1) Source: IHS Chemical

Three Months Ended June 30, 2014 Compared with Three Months Ended June 30, 2013

Refinery services Segment Margin for the 2014 Quarter increased $2.9 million, or 16%. The significant components of this fluctuation were as follows:

•

NaHS revenues increased primarily as a function of increased sales volumes, which increase was partially offset by a decrease in the average index price for caustic soda (which is a component of our sales prices). The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which these adjustments apply varies between periods.

•

Our raw material costs related to NaHS decreased correspondingly to the decrease in the average index price for caustic soda. We were able to realize benefits from 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 revenues decreased slightly, while caustic soda sales volumes increased 11%. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda decreased to $595 per DST in the second quarter of 2014 compared to $626 per DST during the second quarter of 2013. 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.

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Six Months Ended June 30, 2014 Compared with Six Months Ended June 30, 2013

Refinery services Segment Margin for the six month periods increased $5.8 million, or 16%. The significant components of this fluctuation were as follows:

•

Caustic soda revenues increased slightly, while caustic soda sales volumes increased 17%. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda decreased to $587 per DST in the first six months of 2014 compared to $614 per DST during the first six months of 2013. 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,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Supply and logistics revenue	$	939,056		$	994,681		$	1,883,662		$	1,939,226
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(841,547		)	(924,683		)	(1,694,589		)	(1,794,579		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(64,577		)	(45,491		)	(127,299		)	(91,936		)
Segment Margin attributable to discontinued operations	—			312			—			562
Other	156			471			(299		)	921
Segment Margin	$	33,088		$	25,290		$	61,475		$	54,194

Volumetric Data (average barrels per day):
Crude oil and petroleum products sales:
Continuing operations	96,443			106,428			98,631			101,358
Discontinued operations	—			13,220			—			12,194
Total crude oil and petroleum products sales	96,443			119,648			98,631			113,552

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Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets and our logistics capabilities from our terminals, railcars, rail loading and unloading facilities, trucks and barges to provide oil and gas producers, refineries and other customers with a full suite of services. These services include:


•	purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining;


•	supplying petroleum products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets and some end-users such as paper mills and utilities;


•	purchasing products from refiners, transporting the products to one of our terminals and blending the products to a quality that meets the requirements of our customers and selling those products;


•	utilizing our fleet of trucks and trailers, railcars, and barges to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;


•	railcar loading and unloading activities at our crude-by-rail terminals; and


•	industrial gas activities, including wholesale marketing of CO₂and processing of syngas through a joint venture.

Product purchase and sale activities account for a substantial majority of revenues and costs of our supply and logistics segment. For reference purposes, the average market prices of crude oil and petroleum products increased 9% and 7% 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, 2014 Compared with Three Months Ended June 30, 2013

Segment Margin for our supply and logistics segment increased by $7.8 million, or 31% between the two second quarter periods.

In the 2014 Quarter, the increase in our Segment Margin resulted primarily from the contributions from our offshore marine transportation business, which we acquired in August 2013, as well as contributions from our new and expanded assets at our Port Hudson facility which were completed during the first half of 2014. In addition, we continue to transition our refined products operations to a level and structure designed to operate within current market conditions in terms of costs, size and type of activity.

Six Months Ended June 30, 2014 Compared with Six Months Ended June 30, 2013

Segment Margin for our supply and logistics segment increased by $7.3 million, or 13% between the two six month periods.

The increase in our Segment Margin during the first six months of 2014 resulted primarily from the contributions from our offshore marine transportation business, which we acquired in August 2013, as well as contributions from our new and expanded assets at our Port Hudson facility, which were completed during the first half of 2014. This increase was partially offset by the negative impacts we experienced in our refined products business as we worked through the dislocations in the prices/margins for the underlying commodities. We continue to transition our refined products operations to a level and structure designed to operate within current market conditions in terms of costs, size and type of activity.

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Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	11,147	$	7,690	$	18,897	$	14,836
Segment	892		812		1,822		1,506
Equity-based compensation plan expense	2,239		1,973		4,785		5,528
Third party costs related to business development activities and growth projects	418		667		1,202		883
Total general and administrative expenses	$	14,696	$	11,142	$	26,706	$	22,753

Total general and administrative expenses increased $3.6 million and $4.0 million between the three and six month periods, respectively, primarily due to higher employee compensation expenses. Increases in equity-based compensation plan expense were primarily due to an increase in the number of participants when comparing the three months ended June 30, 2014 to the three months ended June 30, 2013. Increases in the market prices of our common units also affect equity-based compensation plan expense. Market prices of our common units increased 3% between June 30, 2014 as compared to March 31, 2014 and increased 7% between June 30, 2013 and March 31, 2013.

Equity-based compensation plan expense decreased when comparing the six months ended June 30, 2014 to the six months ended June 30, 2013, as the market price of our common units increased 7% between June 30, 2014 as compared to December 31, 2013 and increased 45% between June 30, 2013 as compared to December 31, 2012. This is partially offset by an increase in the number of participants as of June 30, 2014 as compared to the number of participants as of June 30, 2013.

Depreciation and amortization expense



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Depreciation expense	$	16,409	$	11,067	$	31,686	$	21,558
Amortization of intangible assets	3,147		3,609		6,292		7,236
Amortization of CO2 volumetric production payments	935		989		1,793		1,920
Total depreciation and amortization expense	$	20,491	$	15,665	$	39,771	$	30,714

Total depreciation and amortization expense increased $4.8 million and $9.1 million, between the three and six month periods, respectively, primarily as a result of our increasing asset base, which was partially offset by a decrease in the amortization of intangible assets. Depreciation expense increased $5.3 million and $10.1 million between the three and six month periods, respectively, primarily as a result of the acquisition of our offshore marine transportation assets and recently completed growth projects. Amortization of intangible assets decreased $0.5 million and $0.9 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.

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Interest expense, net



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	4,344		$	2,417		$	8,172		$	5,221
Interest expense, senior unsecured notes	14,437			11,922			26,359			21,775
Amortization of debt issuance costs and premium	1,216			1,106			2,320			2,128
Capitalized interest	(5,928		)	(3,190		)	(9,978		)	(5,428		)
Net interest expense	$	14,069		$	12,255		$	26,873		$	23,696

Net interest expense increased $1.8 million and $3.2 million between the three and six month periods, respectively, primarily due to our newly issued senior unsecured notes issued in May 2014. 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 $2.7 million and $4.6 million in the three and six month periods, respectively, due to our growth capital expenditures, 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, 2014 included an unrealized loss on derivative positions of $2.7 million. Net income for the same period in 2013 included an unrealized gain on derivative positions of $2.0 million. Net income for the six months ended June 30, 2014 included an unrealized gain on derivative positions of $1.2 million. Net income for the same period in 2013 included an unrealized gain on derivative positions of $2.0 million. Those amounts are included in supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations and are not a component of Segment Margin.

Liquidity and Capital Resources

General

As of June 30, 2014, we had $487.9 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 issuances of equity and senior unsecured notes.

Our primary cash requirements consist of:


•	Working capital, primarily inventories;


•	Routine operating expenses;


•	Capital growth and maintenance projects;


•	Acquisitions of assets or businesses;


•	Payments related to servicing 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 additional capital on satisfactory terms or implement our growth strategy successfully.

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In June 2014, we amended and restated our $1 billion senior secured credit facility with a syndicate of banks to, among other things, extend the term of our credit facility to July 25, 2019. Additionally, the accordion feature was increased from $300 million to $500 million, giving us the ability to expand the size of the facility up to $1.5 billion for acquisitions or 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. At any one time, we can have up to $100 million in letters of credit outstanding under our facility. We had $19.9 million in letters of credit outstanding at June 30, 2014. 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, 2014, we had $492.2 million borrowed under our credit facility, with $105.9 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, 2014 was $487.9 million.

The key interest rate and principal fees under our credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:


•	The applicable margin varies from 1.50% to 2.50% on Eurodollar borrowings and from 0.50% to 1.50% on alternate base rate borrowings.

•Letter of credit fees range from 1.50% to 2.50%

•The commitment fee on the unused committed amount will range from 0.250% to 0.375%.

On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. The notes mature on June 15, 2024.

At June 30, 2014, long-term debt totaled $1.5 billion, consisting of $492.2 million outstanding under our credit facility (including $105.9 million borrowed under the inventory sublimit tranche), a $350.7 million carrying amount of senior unsecured notes due on December 15, 2018, a $350 million carrying amount of senior unsecured notes due on February 15, 2021 and a $350 million carrying amount of senior unsecured notes due on June 15, 2024.

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 a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for 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 those products to one of our storage facilities for further blending or we sell those products 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, utilizing a portion of 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 12 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, 2014 and June 30, 2013.

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The increase in operating cash flow for the six months ended June 30, 2014 compared to the same period in 2013 was primarily due to decreases in working capital needs and increases in cash earnings. 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 working capital and, therefore, our operating cash flows between periods as the cost to acquire a barrel of oil or petroleum products will require more or less cash. Net cash flows provided by our operating activities for the six months ended June 30, 2014 were $105.2 million compared to $95.8 million for the six months ended June 30, 2013.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, growth projects and distributions to unitholders. We finance maintenance capital expenditures and smaller growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and growth projects) 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, 2014 and June 30, 2013 is as follows:



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets	$	2,019	$	284
Refinery services assets	409		414
Supply and logistics assets	1,915		1,879
Total maintenance capital expenditures⁽¹⁾	4,343		2,577
Growth capital expenditures:
Pipeline transportation assets	26,622		54,917
Refinery services assets	490		1,250
Supply and logistics assets	198,771		54,180
Information technology systems	358		958
Total growth capital expenditures	226,241		111,305
Total capital expenditures for fixed and intangible assets	230,584		113,882
Capital expenditures related to equity investees ⁽²⁾	12,676		66,207
Total capital expenditures	$	243,260	$	180,089

(1) Maintenance capital expenditures were $2.1 million and $4.3 million, respectively, for the three and six months ended June 30, 2014.

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

Expenditures for capital assets will depend on our access to debt and equity capital.

Growth Capital Expenditures

Total capital expenditures on projects currently under construction, and described in the following discussion, are estimated to be approximately $720 million, inclusive of capital expenditures incurred in prior periods. We anticipate that approximately $400 million of that total will be spent in 2014, inclusive of expenditures incurred through June 30, 2014.

Gulf Coast Infrastructure

We are improving existing assets and developing 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 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and

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continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at Scenic Station. The Port Hudson upgrades and new crude oil pipeline were completed in the first quarter of 2014, and Scenic Station became fully operational in July 2014.

Baton Rouge Terminal

We previously announced plans to construct a new crude oil, intermediates and refined products import/export terminal in Baton Rouge. That terminal will be located near the Port of Greater Baton Rouge and will be pipeline-connected to that port's existing deepwater docks on the Mississippi River. We will initially construct approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. Our Baton Rouge Terminal will also be pipeline-connected to ExxonMobil facilities in the area, as well as to Scenic Station. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. Our Baton Rouge Terminal is expected to be completed by the end of the second quarter of 2015.

Rail Projects

Walnut Hill - 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 and connections to our Jay System. 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. We completed construction of an additional tank at that site with 110,000 barrels of capacity, which allows us to handle increased rail and pipeline demand and became fully operational in April 2014.

Wink - In 2012, we completed the initial phase construction of a crude oil rail loading facility in Wink, Texas, which was designed to move crude oil from West Texas to other markets and give us the capability to load Genesis and third party railcars. In April 2014, we completed construction on the second phase of that facility, which allows us to more efficiently load full unit trains.

Natchez - In the third quarter of 2013, we completed 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 has the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada. During the first quarter of 2014, we completed construction on the second phase of that facility, which provides an additional 60 railcar spots and additional heated tanks.

Raceland - In the fourth quarter of 2013, we began construction on a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, located in Raceland, Louisiana. The Raceland Rail Facility will be connected to existing midstream infrastructure that will provide direct pipeline access to refineries from the Baton Rouge area to the Gulf of Mexico and is expected to be operational in the second quarter of 2015.

Marine Expansion - We placed orders for 12 barges and 10 push boats to be delivered for our inland marine fleet. During the second quarter of 2014, we accepted delivery of 6 of those barges.

Capital Expenditures Related to Equity Investees

The SEKCO Pipeline, our 50/50 joint venture with Enterprise Products in the deepwater Gulf of Mexico, was declared mechanically complete in June and has been made available to serve the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. We have budgeted approximately $200 million for our cumulative share of the pipeline construction through 2014. In 2013 and 2012, we contributed $94.3 million and $63.7 million, respectively, to SEKCO that was used to fund our share of the construction costs incurred during those years. We have budgeted approximately $40.1 million in 2014, of which we have paid $12.7 million during the first six months of the year.

Distributions to Unitholders

On August 14, 2014, we will pay a distribution of $0.565 per common unit totaling $50.1 million with respect to the second quarter of 2014 to common unitholders of record on August 1, 2014. This is the thirty-sixth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 9 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, 2013.

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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, 2013, 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;


•	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 and the effects of future laws and government regulation;


•	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 indentures governing our notes, which contain various affirmative and negative covenants;


•	the level of indebtedness that we maintain to fund growth projects could adversely affect our financial health;


•	loss of key personnel;


•	cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level or continue to increase quarterly cash distributions in the future;


•	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, which may reduce our earnings, profitability and cash flows;

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•	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, 2013. 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, 2013. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 13 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. On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of June 30, 2014, the Company continues to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

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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, 2013. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

There has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.

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.

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Item 6. Exhibits.

(a) Exhibits



	3.1	Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Registration Statement on Form S-1, File No. 333-11545).
	3.2	Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to Form 10-Q for the quarterly period ended June 30, 2011, File No. 011-12295).
	3.3	Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.5	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.6	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007, File No. 001-12295).
	10.1	Transition, Separation and General Release Agreement for Steven R. Nathanson dated April 11, 2014 (incorporated by reference to Exhibit 99.1 to Form 8-K filed April 14, 2014, File No. 001-12295).
	10.2	Underwriting Agreement dated May 12, 2014 among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and RBC Capital Markets, as representative of the several underwriters (incorporated by reference to Exhibit 1.1 to Form 8-K dated May 15, 2014, File number 1-12294).
	10.3	Indenture dated May 15, 2014, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 1.1 to Form 8-K dated May 15, 2014, File number 1-12294).
	10.4	Supplemental Indenture for the Issuer’s 5.625% Senior Notes due 2024, dated May 15, 2014, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and the U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 1.1 to Form 8-K dated May 15, 2014, File number 1-12294).
	10.5	Fourth Amended and Restated Credit Agreement, dated as of June 30, 2014 among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto incorporated by reference to Exhibit 1.1 to Form 8-K dated July 3, 2014, File number 1-12295).
*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Schema Document
*	101.CAL	XBRL Calculation Linkbase Document
*	101.LAB	XBRL Label Linkbase Document
*	101.PRE	XBRL Presentation Linkbase Document
*	101.DEF	XBRL Definition Linkbase Document



*	Filed herewith

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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 6, 2014	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer