GENESIS ENERGY LP - FORM 10-Q

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EX-32 - EXHIBIT 32 - GENESIS ENERGY LP	gel3312015exhibit32.htm
EXCEL - IDEA: XBRL DOCUMENT - GENESIS ENERGY LP	Financial_Report.xls
EX-31.2 - EXHIBIT 31.2 - GENESIS ENERGY LP	gel3312015exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - GENESIS ENERGY LP	gel3312015exhibit311.htm

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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 March 31, 2015

¨ 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 99,589,221 Class A Common Units and 39,997 Class B Common Units outstanding as of April 28, 2015.

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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	9
	6. Equity Investees	9
	7. Intangible Assets	11
	8. Debt	11
	9. Partners' Capital and Distributions	12
	10. Business Segment Information	12
	11. Transactions with Related Parties	14
	12. Supplemental Cash Flow Information	15
	13. Derivatives	15
	14. Fair-Value Measurements	18
	15. Contingencies	18
	16. Condensed Consolidating Financial Information	19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	42
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults upon Senior Securities	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
SIGNATURES		45

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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)



	March 31, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,138		$	9,462
Accounts receivable - trade, net	202,632			271,529
Inventories	63,802			46,829
Other	30,368			27,546
Total current assets	307,940			355,366
FIXED ASSETS, at cost	2,017,239			1,899,058
Less: Accumulated depreciation	(287,077		)	(268,057		)
Net fixed assets	1,730,162			1,631,001
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	144,458			145,959
EQUITY INVESTEES	620,147			628,780
INTANGIBLE ASSETS, net of amortization	79,918			82,931
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	64,469			61,291
TOTAL ASSETS	$	3,272,140		$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	203,298		$	245,405
Accrued liabilities	139,273			117,740
Total current liabilities	342,571			363,145
SENIOR SECURED CREDIT FACILITY	648,400			550,400
SENIOR UNSECURED NOTES	1,050,604			1,050,639
DEFERRED TAX LIABILITIES	19,363			18,754
OTHER LONG-TERM LIABILITIES	18,326			18,233
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 95,029,218 units issued and outstanding at March 31, 2015 and December 31, 2014, respectively	1,192,876			1,229,203
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	3,272,140		$	3,230,374

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 March 31,
	2015			2014
REVENUES:
Pipeline transportation services	19,858			20,920
Refinery services	46,124			54,193
Marine transportation	57,371			56,293
Supply and logistics	403,504			888,313
Total revenues	526,857			1,019,719
COSTS AND EXPENSES:
Supply and logistics product costs	370,918			849,262
Supply and logistics operating costs	25,239			27,318
Marine transportation operating costs	31,594			35,774
Refinery services operating costs	27,027			33,195
Pipeline transportation operating costs	6,914			7,478
General and administrative	13,221			12,010
Depreciation and amortization	27,125			19,280
Total costs and expenses	502,038			984,317
OPERATING INCOME	24,819			35,402
Equity in earnings of equity investees	15,519			7,818
Interest expense	(19,215		)	(12,804		)
Income before income taxes	21,123			30,416
Income tax expense	(908		)	(641		)
NET INCOME	$	20,215		$	29,775
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.21		$	0.34
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	95,029			88,691

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
	2015	2014	2015			2014
Partners’ capital, January 1	95,029	88,691	$	1,229,203		$	1,097,737
Net income	—	—	20,215			29,775
Cash distributions	—	—	(56,542		)	(47,453		)
Partners' capital, March 31	95,029	88,691	$	1,192,876		$	1,080,059

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)



	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	20,215		$	29,775
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	27,125			19,280
Amortization of debt issuance costs and premium	1,247			1,104
Amortization of unearned income and initial direct costs on direct financing leases	(3,805		)	(3,977		)
Payments received under direct financing leases	5,167			5,315
Equity in earnings of investments in equity investees	(15,519		)	(7,818		)
Cash distributions of earnings of equity investees	18,075			9,944
Non-cash effect of equity-based compensation plans	3,161			2,886
Deferred and other tax liabilities (benefits)	608			341
Unrealized loss (gain) on derivative transactions	1,534			(3,911		)
Other, net	(1,279		)	231
Net changes in components of operating assets and liabilities (Note 12)	5,936			52,918
Net cash provided by operating activities	62,465			106,088
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(111,504		)	(104,254		)
Cash distributions received from equity investees - return of investment	7,827			2,636
Investments in equity investees	(1,750		)	(10,709		)
Proceeds from asset sales	1,768			72
Other, net	29			(1,270		)
Net cash used in investing activities	(103,630		)	(113,525		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	226,200			249,900
Repayments on senior secured credit facility	(128,200		)	(192,200		)
Distributions to common unitholders	(56,542		)	(47,453		)
Other, net	1,383			—
Net cash provided by financing activities	42,841			10,247
Net increase in cash and cash equivalents	1,676			2,810
Cash and cash equivalents at beginning of period	9,462			8,866
Cash and cash equivalents at end of period	$	11,138		$	11,676

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and 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 five divisions that constitute our reportable segments:


•	Onshore pipeline transportation of crude oil and, to a lesser extent, carbon dioxide (or "CO₂");


•	Offshore pipeline transportation of crude oil in the Gulf of Mexico;


•	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");


•	Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; 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, 2014.

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 April 2015, the Financial Accounting Standards Board ("FASB") issued guidance that will require the presentation of debt issuance costs in financial statements as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. Under current U.S. GAAP standards, debt issuance costs are reported as deferred charges (i.e., as an asset). This guidance is effective for annual periods, and interim periods within those fiscal years, beginning after December 15, 2015 and is to be applied retrospectively upon adoption. Early adoption is permitted, including adoption in an interim period for financial statements that have not been previously issued. We are currently evaluating this guidance.

In May 2014, the 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 permits the use of either a full retrospective or a modified retrospective approach.

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In April 2015, the FASB proposed deferring the effective date of this standard by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

3. Acquisition and Divestiture

Acquisition

M/T American Phoenix

On November 13, 2014, we acquired the M/T American Phoenix from Mid Ocean Tanker Company for $157 million. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity that was placed into service during 2012.

The purchase price of $157 million was paid to Mid Ocean Tanker Company in cash, as funded with proceeds from available and committed liquidity under our $1 billion revolving credit facility. We have reflected the financial results of the acquired business in our marine transportation segment from the date of acquisition. We have recorded the assets acquired in the Consolidated Financial Statements at their fair values. Those fair values were developed by management.

The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows:



Property and equipment	$	125,000
Intangible assets	32,000
Total purchase price	$	157,000

Our Consolidated Financial Statements include the results of our acquired offshore marine transportation business since November 13, 2014, the effective closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:



	Three Months Ended March 31,
	2015
Revenues	$	5,580
Net income	$	1,397

The table below presents selected unaudited pro forma financial information incorporating the historical results of our M/T American Phoenix. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2014 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 30 years.



	Three Months Ended March 31,
	2014
Pro forma consolidated financial operating results:
Revenues	$	1,024,570
Net Income	$	31,073

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Inventories

The major components of inventories were as follows:



	March 31, 2015		December 31, 2014
Petroleum products	$	26,791	$	30,108
Crude oil	30,043		7,266
Caustic soda	2,392		2,850
NaHS	4,573		6,603
Other	3		2
Total	$	63,802	$	46,829

Inventories are valued at the lower of cost or market. The market value of inventories was below recorded costs by approximately $0.2 million and $6.6 million at March 31, 2015 and December 31, 2014, respectively; therefore we reduced the value of inventory in our Unaudited Condensed Consolidated Financial Statements for this difference.

5. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	March 31, 2015			December 31, 2014
Pipelines and related assets	$	473,854		$	466,613
Machinery and equipment	382,046			376,672
Transportation equipment	17,983			18,479
Marine vessels	736,638			731,016
Land, buildings and improvements	38,244			38,037
Office equipment, furniture and fixtures	6,866			6,696
Construction in progress	318,890			222,233
Other	42,718			39,312
Fixed assets, at cost	2,017,239			1,899,058
Less: Accumulated depreciation	(287,077		)	(268,057		)
Net fixed assets	$	1,730,162		$	1,631,001

Our depreciation expense for the periods presented was as follows:



	Three Months Ended March 31,
	2015		2014
Depreciation expense	$	22,037	$	15,277

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 March 31, 2015 and December 31, 2014, the unamortized excess cost amounts totaled $212.8 million and $215.4 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	Three Months Ended March 31,
	2015			2014
Genesis’ share of operating earnings	$	18,260		$	10,401
Amortization of excess purchase price	(2,741		)	(2,583		)
Net equity in earnings	$	15,519		$	7,818
Distributions received	$	25,902		$	12,580

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



	March 31, 2015		December 31, 2014
BALANCE SHEET DATA:
Assets
Current assets	$	44,834	$	42,135
Fixed assets, net	1,003,359		1,015,305
Other assets	3,181		4,369
Total assets	$	1,051,374	$	1,061,809
Liabilities and equity
Current liabilities	$	29,232	$	25,369
Other liabilities	202,623		202,613
Equity	819,519		833,827
Total liabilities and equity	$	1,051,374	$	1,061,809



	Three Months Ended March 31,
	2015		2014
INCOME STATEMENT DATA:
Revenues	$	72,090	$	49,824
Operating income	$	48,113	$	30,475
Net income	$	46,917	$	29,706

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Intangible Assets

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



	March 31, 2015						December 31, 2014
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	82,981	$	11,673	$	94,654	$	81,880	$	12,774
Licensing agreements	38,678		29,661		9,017		38,678		28,983		9,695
Segment total	133,332		112,642		20,690		133,332		110,863		22,469
Supply & Logistics:
Customer relationships	35,430		30,601		4,829		35,430		30,228		5,202
Intangibles associated with lease	13,260		3,631		9,629		13,260		3,512		9,748
Segment total	48,690		34,232		14,458		48,690		33,740		14,950
Marine contract intangibles	32,000		2,083		29,917		32,000		833		31,167
Other	23,821		8,968		14,853		22,797		8,452		14,345
Total	$	237,843	$	157,925	$	79,918	$	236,819	$	153,888	$	82,931

Our amortization of intangible assets for the periods presented was as follows:



	Three Months Ended March 31,
	2015		2014
Amortization of intangible assets	$	4,037	$	3,145

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



Remainder of	2015	$	13,922
	2016	$	15,613
	2017	$	14,450
	2018	$	12,334
	2019	$	8,021

8. Debt

Our obligations under debt arrangements consisted of the following:



	March 31, 2015		December 31, 2014
Senior secured credit facility	$	648,400	$	550,400
7.875% senior unsecured notes (including unamortized premium of $604 and $639 in 2015 and 2014, respectively)	350,604		350,639
5.750% senior unsecured notes	350,000		350,000
5.625% senior unsecured notes	350,000		350,000
Total long-term debt	$	1,699,004	$	1,601,039

As of March 31, 2015, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Senior Secured Credit Facility

The key terms for rates under our $1 billion senior secured 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%.

•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.

At March 31, 2015, we had $648.4 million borrowed under our $1 billion credit facility, with $48.3 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 $11.2 million was outstanding at March 31, 2015. 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 March 31, 2015 was $340.4 million.

9. Partners’ Capital and Distributions

At March 31, 2015, our outstanding common units consisted of 94,989,221 Class A units and 39,997 Class B units.

On April 10, 2015, we issued 4,600,000 Class A common units in a public offering at a price of $44.42 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $198 million from that offering. We intend to use the net proceeds for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility.

Distributions

We paid or will pay the following distributions in 2014 and 2015:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2014
1^st Quarter	May 15, 2014		$	0.5500	$	48,783
2^nd Quarter	August 14, 2014		$	0.5650	$	50,114
3^rd Quarter	November 14, 2014		$	0.5800	$	54,112
4^th Quarter	February 13, 2015		$	0.5950	$	56,542
2015
1^st Quarter	May 15, 2015	⁽¹⁾	$	0.6100	$	60,774	⁽²⁾

(1) This distribution will be paid to unitholders of record as of May 1, 2015.

(2) Includes holders of units issued on April 10, 2015.

10. Business Segment Information

In the fourth quarter of 2014, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates resources. The results of our marine transportation activities, formerly reported in the Supply and Logistics Segment, are now reported in our Marine Transportation Segment. In addition, the results of our offshore and onshore pipeline transportation activities, formerly reported in the Pipeline Transportation Segment, are now reported separately in our Onshore Pipeline Transportation Segment and Offshore Pipeline Transportation Segments. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As a result of the above changes, we currently manage our businesses through five divisions that constitute our reportable segments:


•	Onshore Pipeline Transportation – transportation of crude oil, and to a lesser extent, CO₂;


•	Offshore Pipeline Transportation – offshore transportation of crude oil in the Gulf of Mexico;


•	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;


•	Marine Transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; 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:



	Onshore Pipeline Transportation		Offshore Pipeline Transportation		Refinery Services			Marine Transportation		Supply & Logistics			Total
Three Months Ended March 31, 2015
Segment Margin (a)	$	14,323	$	25,198	$	19,160		$	25,693	$	9,747		$	94,121
Capital expenditures (b)	$	68,591	$	2,053	$	1,212		$	16,576	$	36,776		$	125,208
Revenues:
External customers	$	15,831	$	790	$	48,435		$	54,640	$	407,161		$	526,857
Intersegment (c)	3,237		—		(2,311		)	2,731		(3,657		)	—
Total revenues of reportable segments	$	19,068	$	790	$	46,124		$	57,371	$	403,504		$	526,857
Three Months Ended March 31, 2014
Segment Margin (a)	$	14,689	$	13,403	$	20,872		$	20,457	$	7,930		$	77,351
Capital expenditures (b)	$	23,896	$	10,384	$	302		$	10,959	$	57,237		$	102,778
Revenues:
External customers	$	15,503	$	947	$	57,107		$	51,090	$	895,072		$	1,019,719
Intersegment (c)	4,470		—		(2,914		)	5,203		(6,759		)	—
Total revenues of reportable segments	$	19,973	$	947	$	54,193		$	56,293	$	888,313		$	1,019,719

Total assets by reportable segment were as follows:



	March 31, 2015		December 31, 2014
Onshore pipeline transportation	$	491,072	$	460,012
Offshore pipeline transportation	637,412		645,668
Refinery services	401,164		403,703
Marine transportation	744,797		745,128
Supply and logistics	934,699		907,189
Other assets	62,996		68,674
Total consolidated assets	3,272,140		3,230,374


(a)	A reconciliation of Segment Margin to net income for the periods is presented below.

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(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 $1.8 million during the three months ended March 31, 2015 and $10.4 million during the three months ended March 31, 2014 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.

Reconciliation of Segment Margin to net income:



	Three Months Ended March 31,
	2015			2014
Segment Margin	$	94,121		$	77,351
Corporate general and administrative expenses	(12,299		)	(11,061		)
Depreciation and amortization	(27,125		)	(19,280		)
Interest expense	(19,215		)	(12,804		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(10,383		)	(5,777		)
Non-cash items not included in Segment Margin	(2,614		)	3,325
Cash payments from direct financing leases in excess of earnings	(1,362		)	(1,338		)
Income tax expense	(908		)	(641		)
Net income	20,215			29,775


(1)	Includes distributions attributable to the quarter and received during or promptly following such quarter.

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 March 31,
	2015		2014
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	699	$	655
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	195	$	150


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

Amount due from Related Party

At March 31, 2015 and December 31, 2014 Sandhill Group, LLC owed us $0.2 million and $0.3 million, respectively, for purchases of CO₂.

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12. Supplemental Cash Flow Information

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



	Three Months Ended March 31,
	2015			2014
(Increase) decrease in:
Accounts receivable	$	70,903		$	60,046
Inventories	(16,973		)	(11,700		)
Deferred charges	(3,103		)	—
Other current assets	(4,722		)	41,623
Increase (decrease) in:
Accounts payable	(37,826		)	(1,867		)
Accrued liabilities	(2,343		)	(35,184		)
Net changes in components of operating assets and liabilities	5,936			52,918

Payments of interest and commitment fees, net of amounts capitalized, were $14.2 million and $14.0 million for the three months ended March 31, 2015 and March 31, 2014, respectively. We capitalized interest of $3.0 million and $4.1 million during the three months ended March 31, 2015 and March 31, 2014.

At March 31, 2015 and March 31, 2014, we had incurred liabilities for fixed and intangible asset additions totaling $73.7 million and $41.6 million, respectively, that had not been paid at the end of the first 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 March 31, 2015 we had incurred liabilities for other asset additions totaling $12.0 million, that had not been paid at the end of the first 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.

We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the consolidates statements of operations.

In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party's exposure to market volatility and the

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associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets.

At March 31, 2015, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments.



	Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	520		—
Weighted average contract price per bbl	$	47.47	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	353		276
Weighted average contract price per bbl	$	52.02	$	54.27
Crude oil swaps:
Contract volumes (1,000 bbls)	670		—
Weighted average contract price per bbl	$	2.89	$	—
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	340		95
Weighted average contract price per bbl	$	45.46	$	44.95
Crude oil options:
Contract volumes (1,000 bbls)	85		40
Weighted average premium received	$	2.36	$	0.17

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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The following tables reflect the estimated fair value gain (loss) position of our derivatives at March 31, 2015 and December 31, 2014:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	March 31, 2015			December 31, 2014
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	839		$	16,383
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(839		)	(2,310		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	14,073
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Current Assets - Other	$	61		$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(61		)	—
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⁾	$	(2,067	)	$	(2,310	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	2,067			2,310
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(797	)	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	797			—
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 March 31, 2015, we had a net broker receivable of approximately $6.2 million (consisting of initial margin of $5.3 million increased by $0.9 million of variation margin). As of December 31, 2014, we had a net broker receivable of approximately $2.8 million (consisting of initial margin of $2.4 million increased by $0.3 million of variation margin). At March 31, 2015 and December 31, 2014, 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.

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Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended March 31,
		2015			2014
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	2,186		$	—
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	(805		)	2,769
Total commodity derivatives		$	1,381		$	2,769

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 for identical assets and liabilities 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 March 31, 2015 and December 31, 2014.



	Fair Value at							Fair Value at
	March 31, 2015							December 31, 2014
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	900		$	—	$	—	$	16,383		$	—	$	—
Liabilities	$	(2,864	)	$	—	$	—	$	(2,310	)	$	—	$	—

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 of interest for similar instruments with comparable maturities. At both March 31, 2015 and December 31, 2014, our senior unsecured notes had a carrying value of $1.1 billion and a fair value of $1.0 billion. 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.

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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.

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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Unaudited Condensed Consolidating Balance Sheet

March 31, 2015



	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	$	9	$	—	$	8,789		$	2,340		$	—		$	11,138
Other current assets	1,465,246		—		284,622			48,182			(1,501,248		)	296,802
Total current assets	1,465,255		—		293,411			50,522			(1,501,248		)	307,940
Fixed assets, at cost	—		—		1,899,218			118,021			—			2,017,239
Less: Accumulated depreciation	—		—		(263,259		)	(23,818		)	—			(287,077		)
Net fixed assets	—		—		1,635,959			94,203			—			1,730,162
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	27,140		—		269,385			145,184			(152,864		)	288,845
Equity investees	—		—		620,147			—			—			620,147
Investments in subsidiaries	1,417,120		—		126,985			—			(1,544,105		)	—
Total assets	$	2,909,515	$	—	$	3,270,933		$	289,909		$	(3,198,217	)	$	3,272,140
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	17,635	$	—	$	1,818,022		$	8,327		$	(1,501,413	)	$	342,571
Senior secured credit facility	648,400		—		—			—			—			648,400
Senior unsecured notes	1,050,604		—		—			—			—			1,050,604
Deferred tax liabilities	—		—		19,363			—			—			19,363
Other liabilities	—		—		15,130			155,891			(152,695		)	18,326
Total liabilities	1,716,639		—		1,852,515			164,218			(1,654,108		)	2,079,264
Partners’ capital	1,192,876		—		1,418,418			125,691			(1,544,109		)	1,192,876
Total liabilities and partners’ capital	$	2,909,515	$	—	$	3,270,933		$	289,909		$	(3,198,217	)	$	3,272,140

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Unaudited Condensed Consolidating Balance Sheet

December 31, 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	$	9	$	—	$	8,352		$	1,101		$	—		$	9,462
Other current assets	1,378,573		—		327,819			51,781			(1,412,269		)	345,904
Total current assets	1,378,582		—		336,171			52,882			(1,412,269		)	355,366
Fixed assets, at cost	—		—		1,781,158			117,900			—			1,899,058
Less: Accumulated depreciation	—		—		(245,548		)	(22,509		)	—			(268,057		)
Net fixed assets	—		—		1,535,610			95,391			—			1,631,001
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	28,421		—		269,252			146,700			(154,192		)	290,181
Equity investees	—		—		628,780			—			—			628,780
Investments in subsidiaries	1,434,255		—		126,035			—			(1,560,290		)	—
Total assets	$	2,841,258	$	—	$	3,220,894		$	294,973		$	(3,126,751	)	$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	11,016	$	—	$	1,751,548		$	13,013		$	(1,412,432	)	$	363,145
Senior secured credit facility	550,400		—		—			—			—			550,400
Senior unsecured notes	1,050,639		—		—			—			—			1,050,639
Deferred tax liabilities	—		—		18,754			—			—			18,754
Other liabilities	—		—		15,082			157,172			(154,021		)	18,233
Total liabilities	1,612,055		—		1,785,384			170,185			(1,566,453		)	2,001,171
Partners’ capital	1,229,203		—		1,435,510			124,788			(1,560,298		)	1,229,203
Total liabilities and partners’ capital	$	2,841,258	$	—	$	3,220,894		$	294,973		$	(3,126,751	)	$	3,230,374

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2015



	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:
Pipeline transportation services	$	—		$	—	$	13,414		$	6,444		$	—		$	19,858
Refinery services	—			—		45,319			2,112			(1,307		)	46,124
Marine transportation	—			—		57,371			—			—			57,371
Supply and logistics	—			—		401,649			3,966			(2,111		)	403,504
Total revenues	—			—		517,753			12,522			(3,418		)	526,857
COSTS AND EXPENSES:
Supply and logistics costs	—			—		394,834			3,433			(2,110		)	396,157
Marine transportation costs	—			—		31,594			—			—			31,594
Refinery services operating costs	—			—		26,219			2,119			(1,311		)	27,027
Pipeline transportation operating costs	—			—		6,481			433			—			6,914
General and administrative	—			—		13,192			29			—			13,221
Depreciation and amortization	—			—		25,796			1,329			—			27,125
Total costs and expenses	—			—		498,116			7,343			(3,421		)	502,038
OPERATING INCOME	—			—		19,637			5,179			3			24,819
Equity in earnings of subsidiaries	39,407			—		1,387			—			(40,794		)	—
Equity in earnings of equity investees	—			—		15,519			—			—			15,519
Interest (expense) income, net	(19,192		)	—		3,814			(3,837		)	—			(19,215		)
Income before income taxes	20,215			—		40,357			1,342			(40,791		)	21,123
Income tax expense	—			—		(911		)	3			—			(908		)
NET INCOME	$	20,215		$	—	$	39,446		$	1,345		$	(40,791	)	$	20,215

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Unaudited Condensed Consolidating Statement of Operations

Three Months Ended March 31, 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:
Pipeline transportation services	$	—		$	—	$	14,607		$	6,313		$	—		$	20,920
Refinery services	—			—		51,730			6,074			(3,611		)	54,193
Marine transportation	—			—		56,293			—			—			56,293
Supply and logistics	—			—		885,744			32,211			(29,642		)	888,313
Total revenues	—			—		1,008,374			44,598			(33,253		)	1,019,719
COSTS AND EXPENSES:
Supply and logistics costs	—			—		875,346			30,874			(29,640		)	876,580
Marine transportation costs	—			—		35,774			—			—			35,774
Refinery services operating costs	—			—		31,591			5,846			(4,242		)	33,195
Pipeline transportation operating costs	—			—		7,055			423			—			7,478
General and administrative	—			—		11,980			30			—			12,010
Depreciation and amortization	—			—		17,995			1,285			—			19,280
Total costs and expenses	—			—		979,741			38,458			(33,882		)	984,317
OPERATING INCOME	—			—		28,633			6,140			629			35,402
Equity in earnings of subsidiaries	42,579			—		2,164			—			(44,743		)	—
Equity in earnings of equity investees	—			—		7,818			—			—			7,818
Interest (expense) income, net	(12,804		)	—		3,966			(3,966		)	—			(12,804		)
Income before income taxes	29,775			—		42,581			2,174			(44,114		)	30,416
Income tax benefit (expense)	—			—		(587		)	(54		)	—			(641		)
NET INCOME	$	29,775		$	—	$	41,994		$	2,120		$	(44,114	)	$	29,775

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Unaudited Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2015



	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	$	(52,471	)	$	—	$	157,725		$	2,729		$	(45,518	)	$	62,465
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(111,356		)	(148		)	—			(111,504		)
Cash distributions received from equity investees - return of investment	11,013			—		7,827			—			(11,013		)	7,827
Investments in equity investees	—			—		(1,750		)	—			—			(1,750		)
Repayments on loan to non-guarantor subsidiary	—			—		1,329			—			(1,329		)	—
Proceeds from asset sales	—			—		1,768			—			—			1,768
Other, net	—			—		29			—			—			29
Net cash provided by (used) in investing activities	11,013			—		(102,153		)	(148		)	(12,342		)	(103,630		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	226,200			—		—			—			—			226,200
Repayments on senior secured credit facility	(128,200		)	—		—			—			—			(128,200		)
Distributions to partners/owners	(56,542		)	—		(56,542		)	—			56,542			(56,542		)
Other, net	—			—		1,407			(1,342		)	1,318			1,383
Net cash provided by (used in) financing activities	41,458			—		(55,135		)	(1,342		)	57,860			42,841
Net (decrease) increase in cash and cash equivalents	—			—		437			1,239			—			1,676
Cash and cash equivalents at beginning of period	9			—		8,352			1,101			—			9,462
Cash and cash equivalents at end of period	$	9		$	—	$	8,789		$	2,340		$	—		$	11,138

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 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	$	(27,470	)	$	—	$	162,508		$	2,522		$	(31,472	)	$	106,088
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(104,130		)	(124		)	—			(104,254		)
Cash distributions received from equity investees - return of investment	17,222			—		2,636			—			(17,222		)	2,636
Investments in equity investees	—			—		(10,709		)	—			—			(10,709		)
Repayments on loan to non-guarantor subsidiary	—			—		1,201			—			(1,201		)	—
Proceeds from asset sales	—			—		72			—			—			72
Other, net	—			—		(1,270		)	—			—			(1,270		)
Net cash used in investing activities	17,222			—		(112,200		)	(124		)	(18,423		)	(113,525		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	249,900			—		—			—			—			249,900
Repayments on senior secured credit facility	(192,200		)	—		—			—			—			(192,200		)
Distributions to partners/owners	(47,453		)	—		(47,453		)	(1,251		)	48,704			(47,453		)
Other, net	—			—		(42		)	(1,149		)	1,191			—
Net cash provided by (used in) financing activities	10,247			—		(47,495		)	(2,400		)	49,895			10,247
Net (decrease) increase in cash and cash equivalents	(1		)	—		2,813			(2		)	—			2,810
Cash and cash equivalents at beginning of period	20			—		8,061			785			—			8,866
Cash and cash equivalents at end of period	$	19		$	—	$	10,874		$	783		$	—		$	11,676

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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, 2014.

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


•	Overview


•	Segment Reporting Change


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income of $20.2 million, or $0.21 per common unit, during the three months ended March 31, 2015 (“2015 Quarter”) compared to net income of $29.8 million or $0.34 per common unit, during the three months ended March 31, 2014 (“2014 Quarter”).

Available Cash before Reserves increased $10.6 million, or 20%, in the 2015 Quarter (as compared to the 2014 Quarter) to $64.0 million. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin (as described below in “Financial Measures”) increased by $16.8 million, or 22%, in the 2015 Quarter, as compared to the 2014 Quarter.

The increase in our Segment Margin resulted primarily from increases attributable to our offshore pipeline transportation, marine transportation and supply and logistics segments of $12 million, $5 million and $1.8 million, respectively. These increases, as discussed in more detail below and partially offset by small decreases in onshore pipeline transportation and refinery services segment margin, are primarily related to assets recently acquired. Those acquisitions similarly benefited Available Cash before Reserves and net income.

The above factors benefiting net income were partially offset by increases in depreciation and amortization expenses as a result of the effect of recently acquired and constructed assets placed in service, as well as an increase in interest expense due to an increase in our average outstanding indebtedness from newly acquired and constructed assets.

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

Distribution Increase

In April 2015, we declared our thirty-ninth consecutive increase in our quarterly distribution to our common unitholders. Thirty-four of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In May 2015, we will pay a distribution of $0.61 per unit representing a 10.9% increase from our distribution of $0.55 per unit related to the first quarter of 2014.

Segment Reporting Change

As a result of the above changes, we currently manage our businesses through five divisions that constitute our reportable segments - Onshore Pipeline Transportation, Offshore Pipeline Transportation, Refinery Services, Marine Transportation and Supply and Logistics. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

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Financial Measures

For definitions and discussion of the financial measures refer to the "Financial Measures" as later discussed and defined.

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



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Net income	$	20,215		$	29,775
Depreciation and amortization	27,125			19,280
Cash received from direct financing leases not included in income	1,362			1,338
Cash effects of sales of certain assets	1,768			72
Effects of distributable cash generated by equity method investees not included in income	10,383			5,777
Cash effects of legacy stock appreciation rights plan	(288		)	(810		)
Non-cash legacy stock appreciation rights plan expense	686			7
Expenses related to acquiring or constructing growth capital assets	417			784
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value	2,062			(3,781		)
Maintenance capital utilized	(591		)	(112		)
Non-cash tax expense	608			341
Other items, net	291			764
Available Cash before Reserves	$	64,038		$	53,435

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2015 Quarter decreased $492.9 million, or 48%, from the 2014 Quarter. Additionally, our costs and expenses decreased $482.3 million, or 49%, 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 first quarter periods is primarily attributable to a decrease in market prices for crude oil and petroleum products as described below.

The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") decreased 50% to $48.64 per barrel in the first quarter of 2015, as compared to $97.77 per barrel in the first quarter of 2014.

In general, we do not expect fluctuations in prices for oil and gas to affect our Segment Margin to the same extent they affect our revenues and costs. We have limited our direct commodity price exposure through the broad use of fee based services contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of oil would similarly impact both our revenues and our costs with a disproportionate smaller net impact on our Segment Margin.

Our indirect exposure to the impacts of changes in the price of crude oil are mitigated by our strategy of focusing on customers whose operations tend to be less adversely affected by decreases in the price of crude oil. These customers are refiners and other onshore customers who operate further down the energy value chain (as opposed to producers). Our crude oil pipelines in the Gulf of Mexico represent the single largest departure from our “refinery-centric” customer strategy. The shippers on those pipelines are mostly integrated and large independent energy companies who have developed, and continue to explore for, numerous large-reservoir, long-lived crude oil properties whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in this lower commodity price environment.

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Segment Margin

The contribution of each of our segments to total Segment Margin in the three months ended March 31, 2015 and March 31, 2014 was as follows:



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Onshore pipeline transportation	$	14,323	$	14,689
Offshore pipeline transportation	25,198		13,403
Refinery services	19,160		20,872
Marine transportation	25,693		20,457
Supply and logistics	9,747		7,930
Total Segment Margin	$	94,121	$	77,351

A reconciliation of Segment Margin to Net Income for the periods presented is as follows:



	Three Months Ended March 31,
	2015			2014
Segment Margin	$	94,121		$	77,351
Corporate general and administrative expenses	(12,299		)	(11,061		)
Depreciation and amortization	(27,125		)	(19,280		)
Interest expense	(19,215		)	(12,804		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(10,383		)	(5,777		)
Non-cash items not included in Segment Margin	(2,614		)	3,325
Cash payments from direct financing leases in excess of earnings	(1,362		)	(1,338		)
Income tax expense	(908		)	(641		)
Net income	$	20,215		$	29,775

(1) Includes distributions attributable to the quarter and received during or promptly following such quarter.

Our reconciliation of Segment Margin to net income 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 net income 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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Onshore Pipeline Transportation Segment

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



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	10,343		$	10,245
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	6,363			6,507
Sales of onshore crude oil pipeline loss allowance volumes	1,065			1,210
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(5,070		)	(4,870		)
Payments received under direct financing leases not included in income	1,362			1,338
Other	260			259
Segment Margin	$	14,323		$	14,689

Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	75,437			48,811
Jay	15,472			27,853
Mississippi	14,929			15,180
Louisiana ⁽¹⁾	16,786			13,395
Onshore crude oil pipelines total	122,624			105,239

CO₂ pipeline (average Mcf/day):
Free State	190,507			191,593

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

Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Onshore Pipeline Transportation Segment Margin for the 2015 Quarter decreased $0.4 million, or 2%. The significant components and details of this change were as follows:


•	Onshore crude oil pipeline loss allowance volumes, collected and sold, resulted in a slight decrease in segment margin quarter over quarter of $0.1 million. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on that system.

•

With respect to our onshore crude oil pipelines, tariff revenues increased slightly by $0.1 million quarter to quarter, primarily due to a net increase in throughput volumes 17,385 barrels per day, which was primarily the result of increased volumes on our Texas and Louisiana pipeline systems. These increases were partially offset by volume variances on our other onshore pipeline systems. These variances include a decrease in volumes on our Jay pipeline system, which is primarily attributable to a decrease in volumes entering the pipeline through our Walnut Hill rail facility. Due to a mix of tariff rates on our onshore pipelines, the impact on onshore crude oil tariffs and revenues from these volume variances largely offset each other.


•	Onshore pipeline operating costs, excluding non-cash charges, increased $0.2 million due to general increases in operating costs inclusive of safety program costs.

•

Although volumes on our Free State CO₂ pipeline system decreased 1,086 Mcf per day, or 1%, in the 2015 Quarter as compared to the 2014 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.

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Offshore Pipeline Transportation Segment

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



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Offshore Pipeline Transportation Segment Margin⁽¹⁾	$	25,198	$	13,403

Volumetric Data (average barrels/day unless otherwise noted):
Offshore crude oil pipelines:
CHOPS⁽²⁾	172,058		191,326
Poseidon ⁽²⁾	229,058		211,012
Odyssey ⁽²⁾	48,564		45,003
GOPL	6,207		7,449
SEKCO ^{(2) (3)}	21,839		—
Offshore crude oil pipelines total	477,726		454,790


(1)	Offshore Pipeline Transportation segment margin includes approximately $25 million and $13 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2015 and 2014, respectively.


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


(3)	Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO’s transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude until January 2015. Volumes reported for the quarter ended March 31, 2015 for SEKCO reflect the gradual commencement of throughput beginning in January of 2015.

Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Offshore Pipeline Transportation Segment Margin for 2015 increased $11.8 million, or 88%, from 2014. This increase is primarily attributable to the SEKCO pipeline, our 50/50 joint venture with Enterprise Products, being completed and earning certain minimum fees and commencing throughput of crude in January 2015. While throughput has commenced on the SEKCO pipeline, throughput volumes have yet to exceed a level where throughput revenues would exceed the monthly minimum payments currently being received. Volume variances on our offshore pipeline systems excluding SEKCO largely offset each other.

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Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended March 31,
	2015			2014
Volumes sold (in Dry short tons "DST"):
NaHS volumes	32,430			40,902
NaOH (caustic soda) volumes	21,186			24,033
Total	53,616			64,935

Revenues (in thousands):
NaHS revenues	$	35,453		$	43,108
NaOH (caustic soda) revenues	10,874			12,145
Other revenues	2,108			1,854
Total external segment revenues	$	48,435		$	57,107

Segment Margin (in thousands)	$	19,160		$	20,872

Average index price for NaOH per DST ⁽¹⁾	$	588		$	579
Raw material and processing costs as % of segment revenues	42		%	44		%

(1) Source: IHS Chemical

Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Refinery services Segment Margin for the 2015 Quarter decreased $1.7 million, or 8%. The significant components and details of this change were as follows:

•

NaHS revenues decreased 17.8% primarily due to a decrease in volumes. NaHS sales volumes decreased between the quarterly periods primarily due to a decrease in sales to South American customers in the 2015 Quarter. This decrease was reflective of the timing of certain bulk deliveries to our South American customers which resulted in decreased sales volumes, rather than an overall decrease in NaHS demand. 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.

•

Our raw material costs related to NaHS decreased slightly in spite of a slight increase 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, which somewhat offset the effects on Segment Margin of decreased NaHS sales volumes.

•

Caustic soda revenues decreased 10% due to a reduction in our sales volumes, as well as a decrease in our sales price for caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda increased to $588 per DST in the first quarter of 2015 compared to $579 per DST during the first quarter of 2014. 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

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

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 71 barges (62 inland and 9 offshore) with a combined transportation capacity of 2.6 million barrels, 34 push/tow boats (25 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:



	Three Months Ended March 31,
	2015			2014
Revenues (in thousands):
Inland freight revenues	$	23,385		$	21,723
Offshore freight revenues	24,608			19,956
Other rebill revenues ⁽¹⁾	9,378			14,614
Total segment revenues	$	57,371		$	56,293

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	31,678		$	35,836

Segment Margin (in thousands)	$	25,693		$	20,457

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	96.1		%	98.7		%
Offshore Barge Utilization	100.0		%	100.0		%

(1) Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.

(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.

Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Marine Transportation Segment Margin for 2015 increased $5.2 million, or 26%, from 2014. This increase in Segment Margin in the 2015 quarter is primarily due to a full quarter of operating results from the M/T American Phoenix (included as part of our offshore marine fleet), which we acquired in November 2014.

Utilization rates on our both our inland and offshore barge fleets did not change significantly between the respective quarters. The decrease in operating costs, a large portion of which relate to fuel and other rebillable charges, was largely offset by the decrease in other rebill revenues.

Supply and Logistics Segment

Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets to provide oil and gas producers, refineries and other customers with a full suite of services. Our supply and logistics segment owns or leases trucks, terminals, gathering pipelines, railcars, and rail loading and unloading facilities. It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for its own account. These services include:


•	utilizing the fleet of trucks, trailers and railcars owned or leased by our supply and logistics segment to transport products (primarily crude oil and petroleum products) for customers;


•	utilizing various modes of transportation owned by third parties and us to transport products (primarily crude oil and petroleum products) for our own account to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;


•	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;

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•	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;


•	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.

We also use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity and sulfur content, among others. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources meeting their requirements and to purchase the crude oil and transport it to the refineries for sale. The imbalances and inefficiencies relative to meeting the refiners’ requirements can provide opportunities for us to utilize our skills and assets to meet their demands. The pricing in the majority of our purchase contracts contains a market price component and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts sometimes contain a grade differential which considers the composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

In our petroleum products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.

We utilize our fleet of trucks, trailers, railcars, and leased and owned storage capacity to service our crude oil and refining customers and to store and blend the intermediate and finished refined products.

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



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Supply and logistics revenue	$	403,504		$	888,313
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(368,855		)	(853,042		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(24,909		)	(26,936		)
Other	7			(405		)
Segment Margin	$	9,747		$	7,930

Volumetric Data (average barrels per day):
Total crude oil and petroleum products sales	94,193			100,856
Rail load/unload volumes ⁽¹⁾	15,407			26,611

(1) Indicates total barrels for which fees were charged for either loading or unloading at all rail facilities.

Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Segment Margin for our supply and logistics segment increased by $1.8 million, or 23% between the two first quarter periods.

In the 2015 Quarter, the increase in our Segment Margin is primarily the result of improvements in our heavy fuel oil business. These improvements included a reduction in volumes and related infrastructure in our refined products business as we continue to "right size" our heavy fuel oil business to match the lower volumes of blend materials currently available for us to economically handle compared to the volumes that have historically been available to us. This new market reality has resulted, primarily, from the general lightening of refineries' crude slates resulting in a better supply/demand balance between heavy refined bottoms and domestic coker and asphalt requirements.

The increase in Segment Margin resulting from the improvements in our heavy fuel oil business was partially offset by decreases in fees earned on rail load/unload volumes, which is primarily the result of a decrease in rail unload volumes at our Walnut Hill rail facility.

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended March 31,
	2015		2014
	(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	9,671	$	7,750
Segment	905		930
Equity-based compensation plan expense	2,228		2,546
Third party costs related to business development activities and growth projects	417		784
Total general and administrative expenses	$	13,221	$	12,010

Total general and administrative expenses increased $1.2 million between the three month periods primarily due to higher employee compensation expenses, partially offset by decreases in third party costs related to business development and growth activities. Decreases in equity-based compensation plan expense were primarily due to a smaller increase in the market price of our common units in the 2015 quarter as compared to 2014. As of March 31, 2015, the market price of our common units was $47.00 as compared to $54.20 on March 31, 2014.

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Depreciation and amortization expense



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Depreciation expense	$	22,037	$	15,277
Amortization of intangible assets	4,037		3,145
Amortization of CO2 volumetric production payments	1,051		858
Total depreciation and amortization expense	$	27,125	$	19,280

Total depreciation and amortization expense increased $7.8 million between the quarterly periods primarily as a result of placing newly acquired and constructed assets in service during calendar 2014 and the early part of 2015. Depreciation expense increased $6.8 million between the three month periods, primarily as a result of the acquisition of the M/T American Phoenix (included as part of our offshore marine fleet) and recently completed internal growth projects. Amortization of intangible assets increased $0.9 million between the three month periods, as we amortize our intangible assets over the period in which we expect them to contribute to our future cash flows.

Interest expense, net



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Interest expense, credit facility (including commitment fees)	$	4,147		$	3,828
Interest expense, senior unsecured notes	16,844			11,922
Amortization of debt issuance costs and premium	1,247			1,104
Capitalized interest	(3,023		)	(4,050		)
Net interest expense	$	19,215		$	12,804

Net interest expense increased $6.4 million between the three month periods primarily due to an increase in our average outstanding indebtedness from newly acquired and constructed assets. In May 2014, we issued an additional $350 million of aggregate principal amount of 5.625% senior unsecured notes to repay borrowings under our senior secured credit facility. Capitalized interest costs decreased $1.0 million over the three month periods primarily due to the completion of construction of the SEKCO pipeline, on which we had incurred capitalized interest cost prior to its completion in June 2014.

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 March 31, 2015 included an unrealized loss on derivative positions, excluding fair value hedges, of $1.5 million. Net income for the same period in 2014 included an unrealized gain on derivative positions of $3.9 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. Additionally, the increase in equity in earnings of equity investees of $7.7 million was exceeded by the increase in the distributions of the available cash received from our equity investees of $13.3 million. Such distributions are a component of segment margin.

Liquidity and Capital Resources

General

As of March 31, 2015, we had $340.4 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

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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.

At March 31, 2015, long-term debt totaled $1.7 billion, consisting of $648.4 million outstanding under our credit facility (including $48.3 million borrowed under the inventory sublimit tranche), a $350.6 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/or 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 the products to one of our storage facilities for further blending or we sell the 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 oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the 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 three months ended March 31, 2015 and March 31, 2014.

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The decrease in operating cash flow for the three months ended March 31, 2015 compared to the same period in 2014 was primarily due to increases in working capital needs. 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 three months ended March 31, 2015 were $62.5 million compared to $106.1 million for the three months ended March 31, 2014.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal growth projects and distributions we pay to our unitholders. We finance maintenance capital expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and internal 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 three months ended March 31, 2015 and March 31, 2014 is as follows:



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Onshore pipeline transportation assets	$	1,266	$	1,653
Offshore pipeline transportation assets	175		—
Refinery services assets	1,173		28
Marine transportation assets	10,131		467
Supply and logistics assets	2,458		110
Information technology systems	118		—
Total maintenance capital expenditures	15,321		2,258
Growth capital expenditures:
Onshore pipeline transportation assets	67,325		22,243
Offshore pipeline transportation assets	128		—
Refinery services assets	39		274
Marine transportation assets	6,445		10,492
Supply and logistics assets	34,318		57,127
Information technology systems	158		132
Total growth capital expenditures	108,413		90,268
Total capital expenditures for fixed and intangible assets	123,734		92,526
Capital expenditures related to equity investees ⁽¹⁾	1,750		10,384
Total capital expenditures	$	125,484	$	102,910

(1) Amounts represent our investment in the SEKCO pipeline joint venture.

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

Growth Capital Expenditures

Total capital expenditures on projects under construction are estimated to be approximately $520 million in 2015 and in future periods, inclusive of expenditures incurred through March 31, 2015. We anticipate that approximately $290 million of that total will be spent in 2015, inclusive of expenditures incurred through March 31, 2015. The most significant of these projects currently under construction are described below.

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Baton Rouge Terminal

We are constructing a new crude oil, intermediates and refined products import/export terminal in Baton Rouge that 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. In addition, we will construct a new pipeline from the terminal that will allow for deliveries to existing Exxon Mobil facilities in the area, as well as connect our previously constructed 17 mile line to the terminal allowing for receipts from the Scenic Station Rail Facility. 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. The Baton Rouge Terminal is expected to be operational by the end of the third quarter of 2015.

Raceland Rail Facility

The Raceland Rail Facility, a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, which is located in Raceland, Louisiana, and will be connected to existing midstream infrastructure that will provide direct pipeline access to the Louisiana refining markets and is expected to be operational in the second half of 2015.

Inland Marine Barge Transportation Expansion

We ordered 12 new-build barges and 10 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of 8 of these barges and 3 of those push boats as of March 2015. We expect to take delivery of those remaining vessels periodically into 2016.

Maintenance Capital Expenditures

Maintenance capital expenditures have annually ranged between $3 million and $15 million. As we place more assets into service, particularly as relating to our marine transportation assets, our maintenance capital expenditures may continue to increase in future years. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before reserves.

Distributions to Unitholders

On May 15, 2015, we will pay a distribution of $0.61 per common unit totaling $60.8 million with respect to the first quarter of 2015 to common unitholders of record on May 1, 2015 inclusive of the holders of units issued on April 10, 2015. This is the thirty-ninth 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.

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 net income 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.

Available Cash before Reserves

Overview

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. Our Non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. 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 measures should not be

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considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves measures is just one of the relevant data points considered from time to time.

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user.

Purposes, Uses and Definition

Available Cash before Reserves, also referred to as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and 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 aid in assessing, among other things:


(1)	the financial performance of our assets;


(2)	our operating performance;


(3)	the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;


(4)	the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and


(5)	our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

We define Available Cash before Reserves as net income as adjusted for specific items, the most significant of which are the addition of certain non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows and the subtraction of maintenance capital utilized, which is described in detail below.

Recent Change in Circumstances and Disclosure Format

We have implemented a modified format relating to maintenance capital requirements because of our expectation that our future maintenance capital expenditures may change materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with new information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

Maintenance Capital Requirements

MAINTENANCE CAPITAL EXPENDITURES

Maintenance capital expenditures are 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. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.

Historically, substantially all of our maintenance capital expenditures have been (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would

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not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

Prospectively, we believe a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those future expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s recently increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a new measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves. Our maintenance capital utilized measure, which is described in more detail below, constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

MAINTENANCE CAPITAL UTILIZED

We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we 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 our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013. Further, we do not have the actual comparable calculations for our prior periods, and we may not have the information necessary to make such calculations for such periods. And, even if we could locate and/or re-create the information necessary to make such calculations, we believe it would be unduly burdensome to do so in comparison to the benefits derived.

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, 2014.

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, 2014, 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

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


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


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


•	loss of key personnel;


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


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


•	our financial and commodity hedging arrangements


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


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers or counterparties;


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


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


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

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014. 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2014. 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.

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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, 2014. 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, 2014, except as supplemented by our Quarterly Reports on Form 10-Q and Periodic Reports on Form 8-K. For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014, as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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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).
*	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:	April 29, 2015	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer

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