Edgar Filing: GENESIS ENERGY LP

GEL 6.30.2015 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 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 109,939,221 Class A Common Units and 39,997 Class B Common Units outstanding as of July 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. Subsequent Events	7
	3. Recent Accounting Developments	8
	4. Acquisition and Divestiture	8
	5. Inventories	9
	6. Fixed Assets	9
	7. Equity Investees	10
	8. Intangible Assets	11
	9. Debt	11
	10. Partners' Capital and Distributions	12
	11. Business Segment Information	13
	12. Transactions with Related Parties	15
	13. Supplemental Cash Flow Information	16
	14. Derivatives	16
	15. Fair-Value Measurements	19
	16. Contingencies	19
	17. Condensed Consolidating Financial Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	47
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults upon Senior Securities	49
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	50
SIGNATURES		52

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)



	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8,719		$	9,462
Accounts receivable - trade, net	273,567			271,529
Inventories	54,566			46,829
Other	22,918			27,546
Total current assets	359,770			355,366
FIXED ASSETS, at cost	2,120,646			1,899,058
Less: Accumulated depreciation	(304,876		)	(268,057		)
Net fixed assets	1,815,770			1,631,001
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	142,919			145,959
EQUITY INVESTEES	614,409			628,780
INTANGIBLE ASSETS, net of amortization	75,914			82,931
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	70,453			61,291
TOTAL ASSETS	$	3,404,281		$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	235,758		$	245,405
Accrued liabilities	106,360			117,740
Total current liabilities	342,118			363,145
SENIOR SECURED CREDIT FACILITY	585,200			550,400
SENIOR UNSECURED NOTES	1,100,000			1,050,639
DEFERRED TAX LIABILITIES	20,005			18,754
OTHER LONG-TERM LIABILITIES	15,469			18,233
COMMITMENTS AND CONTINGENCIES (Note 16)
PARTNERS’ CAPITAL:
Common unitholders, 99,629,218 and 95,029,218 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively	1,341,489			1,229,203
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	3,404,281		$	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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES:
Pipeline transportation services	20,191			23,192			40,049			44,112
Refinery services	46,324			52,801			92,448			106,994
Marine transportation	62,594			55,948			119,965			112,241
Supply and logistics	527,218			883,108			930,722			1,771,421
Total revenues	656,327			1,015,049			1,183,184			2,034,768
COSTS AND EXPENSES:
Supply and logistics product costs	492,125			844,395			863,043			1,693,657
Supply and logistics operating costs	23,782			27,774			49,021			55,092
Marine transportation operating costs	35,286			36,905			66,880			72,679
Refinery services operating costs	25,835			31,148			52,862			64,343
Pipeline transportation operating costs	6,882			8,383			13,796			15,861
General and administrative	14,832			14,696			28,053			26,706
Depreciation and amortization	28,205			20,491			55,330			39,771
Total costs and expenses	626,947			983,792			1,128,985			1,968,109
OPERATING INCOME	29,380			31,257			54,199			66,659
Equity in earnings of equity investees	18,661			4,922			34,180			12,740
Interest expense	(17,905		)	(14,069		)	(37,120		)	(26,873		)
Other income/(expense), net	(17,529		)	—			(17,529		)	—
Income before income taxes	12,607			22,110			33,730			52,526
Income tax expense	(942		)	(962		)	(1,850		)	(1,603		)
NET INCOME	$	11,665		$	21,148		$	31,880		$	50,923
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.12		$	0.24		$	0.33		$	0.57
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	99,174			88,691			97,113			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	—	—	31,880			50,923
Cash distributions	—	—	(117,316		)	(96,236		)
Issuance of common units for cash, net	4,600	—	197,722			—
Partners' capital, June 30	99,629	88,691	$	1,341,489		$	1,052,424

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,880		$	50,923
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	55,330			39,771
Amortization of debt issuance costs and premium	6,526			2,320
Amortization of unearned income and initial direct costs on direct financing leases	(7,566		)	(7,922		)
Payments received under direct financing leases	10,333			10,631
Equity in earnings of investments in equity investees	(34,180		)	(12,740		)
Cash distributions of earnings of equity investees	38,811			21,452
Non-cash effect of equity-based compensation plans	4,744			6,267
Deferred and other tax liabilities	1,250			853
Unrealized loss (gain) on derivative transactions	1,309			(1,187		)
Other, net	(2,296		)	1,518
Net changes in components of operating assets and liabilities (Note 13)	(35,039		)	(6,689		)
Net cash provided by operating activities	71,102			105,197
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(240,646		)	(240,994		)
Cash distributions received from equity investees - return of investment	11,490			6,173
Investments in equity investees	(1,750		)	(14,826		)
Proceeds from asset sales	2,228			133
Other, net	(729		)	(2,635		)
Net cash used in investing activities	(229,407		)	(252,149		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	550,500			1,181,200
Repayments on senior secured credit facility	(515,700		)	(1,271,800		)
Proceeds from issuance of senior unsecured notes	400,000			350,000
Repayment of senior unsecured notes	(350,000		)	—
Debt issuance costs	(8,418		)	(10,752		)
Issuance of common units for cash, net	197,722			—
Distributions to common unitholders	(117,316		)	(96,236		)
Other, net	774			—
Net cash provided by financing activities	157,562			152,412
Net increase in cash and cash equivalents	(743		)	5,460
Cash and cash equivalents at beginning of period	9,462			8,866
Cash and cash equivalents at end of period	$	8,719		$	14,326

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. Subsequent Events

In July 2015, we acquired the offshore pipeline and services business of Enterprise Products Operating, LLC and its affiliates for approximately $1.5 billion. That business includes assets of approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms that serve some of the most active drilling and development regions in the United States, including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. At the closing of that transaction, we entered into transition service agreements to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. That acquisition complements and substantially expands our existing offshore pipelines segment.

To finance that transaction, in July, we sold 10,350,000 common units in a public offering that generated proceeds of $437.2 million net of underwriter discounts and $750 million aggregate principal amount of 6.75% senior unsecured notes due 2022 that generated proceeds of $728.6 million net of issuance discount and underwriting fees. The financial statements and footnotes filed herewith do not include the effects of this transaction.

Due to the timing of the acquisition, our initial purchase accounting was incomplete at the time these financial statements were issued. As such, we cannot disclose the allocation of the acquisition price to acquired assets and liabilities and the related required disclosures at this time.

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3. 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.

In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved 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.

4. 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 June 30, 2015		Six Months Ended June 30, 2015
Revenues	$	5,642	$	11,222
Net income	$	1,274	$	2,671

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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 June 30, 2014		Six Months Ended June 30, 2014
Pro forma consolidated financial operating results:
Revenues	$	1,019,900	$	2,044,470
Net Income	$	22,478	$	53,551

5. Inventories

The major components of inventories were as follows:



	June 30, 2015		December 31, 2014
Petroleum products	$	28,043	$	30,108
Crude oil	20,636		7,266
Caustic soda	2,320		2,850
NaHS	3,567		6,603
Other	—		2
Total	$	54,566	$	46,829

Inventories are valued at the lower of cost or market. At June 30, 2015, market values of our inventories exceeded recorded costs. At December 31, 2014 , market value of inventories was below recorded costs by approximately $6.6 million, so we reduced the value of inventory as of that date in our Condensed Consolidated Financial Statements for this difference.

6. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	June 30, 2015			December 31, 2014
Pipelines and related assets	$	477,815		$	466,613
Machinery and equipment	393,913			376,672
Transportation equipment	17,216			18,479
Marine vessels	750,444			731,016
Land, buildings and improvements	39,772			38,037
Office equipment, furniture and fixtures	7,126			6,696
Construction in progress	387,903			222,233
Other	46,457			39,312
Fixed assets, at cost	2,120,646			1,899,058
Less: Accumulated depreciation	(304,876		)	(268,057		)
Net fixed assets	$	1,815,770		$	1,631,001

Our depreciation expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Depreciation expense	$	22,512	$	16,409	$	44,549	$	31,686

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At June 30, 2015 and December 31, 2014, the unamortized excess cost amounts totaled $210.2 million and $215.4 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Genesis’ share of operating earnings	$	21,403		$	7,505		$	39,663		$	17,906
Amortization of excess purchase price	(2,742		)	(2,583		)	(5,483		)	(5,166		)
Net equity in earnings	$	18,661		$	4,922		$	34,180		$	12,740
Distributions received	$	24,399		$	15,045		$	50,301		$	27,625

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



	June 30, 2015		December 31, 2014
BALANCE SHEET DATA:
Assets
Current assets	$	50,963	$	42,135
Fixed assets, net	989,168		1,015,305
Other assets	1,938		4,369
Total assets	$	1,042,069	$	1,061,809
Liabilities and equity
Current liabilities	$	26,521	$	25,369
Other liabilities	202,633		202,613
Equity	812,915		833,827
Total liabilities and equity	$	1,042,069	$	1,061,809



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
INCOME STATEMENT DATA:
Revenues	$	82,553	$	46,440	$	154,643	$	96,264
Operating income	$	56,408	$	22,628	$	104,521	$	53,103
Net income	$	55,230	$	21,815	$	102,147	$	51,521

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Intangible Assets

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



	June 30, 2015						December 31, 2014
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	84,083	$	10,571	$	94,654	$	81,880	$	12,774
Licensing agreements	38,678		30,339		8,339		38,678		28,983		9,695
Segment total	133,332		114,422		18,910		133,332		110,863		22,469
Supply & Logistics:
Customer relationships	35,430		31,082		4,348		35,430		30,228		5,202
Intangibles associated with lease	13,260		3,749		9,511		13,260		3,512		9,748
Segment total	48,690		34,831		13,859		48,690		33,740		14,950
Marine contract intangibles	32,000		3,333		28,667		32,000		833		31,167
Other	21,533		7,055		14,478		22,797		8,452		14,345
Total	$	235,555	$	159,641	$	75,914	$	236,819	$	153,888	$	82,931

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Amortization of intangible assets	$	4,154	$	3,147	$	8,191	$	6,292

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



Remainder of	2015	$	9,761
	2016	$	15,628
	2017	$	14,465
	2018	$	12,349
	2019	$	8,036

9. Debt

Our obligations under debt arrangements consisted of the following:



	June 30, 2015		December 31, 2014
Senior secured credit facility	$	585,200	$	550,400
7.875% senior unsecured notes (including unamortized premium of $639 in 2014)	—		350,639
6.000% senior unsecured notes	400,000		—
5.750% senior unsecured notes	350,000		350,000
5.625% senior unsecured notes	350,000		350,000
Total long-term debt	$	1,685,200	$	1,601,039

As of June 30, 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 June 30, 2015, we had $585.2 million borrowed under our $1 billion credit facility, with $43.4 million of the borrowed amount designated as a loan under the inventory sublimit. The credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $30.6 million was outstanding at June 30, 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 June 30, 2015 was $384.2 million.

Senior Unsecured Note Issuance and Repayment

On May 21, 2015, we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes at face value. Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Those notes mature on May 15, 2023. We used a portion of the proceeds from those notes to redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018. The aggregate principal amount of the 7.875% notes totaling $300.1 million were tendered and the remaining $49.9 million were redeemed in full. A total loss of approximately $19.2 million for the tender and redemption of notes is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations.

10. Partners’ Capital and Distributions

At June 30, 2015, our outstanding common units consisted of 99,589,221 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		$	0.6100	$	60,774
2^nd Quarter	August 14, 2015	⁽¹⁾	$	0.6250	$	68,737

(1) This distribution will be paid to unitholders of record as of July 31, 2015.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. 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 Segment. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

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.

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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 June 30, 2015
Segment margin (a)	$	14,363	$	25,100	$	20,221		$	27,225	$	11,658		$	98,567
Capital expenditures (b)	$	40,893	$	86	$	238		$	11,086	$	55,850		$	108,153
Revenues:
External customers	$	15,856	$	1,258	$	48,786		$	60,603	$	529,824		$	656,327
Intersegment (c)	3,077		—		(2,462		)	1,991		(2,606		)	—
Total revenues of reportable segments	$	18,933	$	1,258	$	46,324		$	62,594	$	527,218		$	656,327
Three Months Ended June 30, 2014
Segment margin (a)	$	16,531	$	11,435	$	21,627		$	18,978	$	14,110		$	82,681
Capital expenditures (b)	$	3,845	$	3,192	$	597		$	37,077	$	95,413		$	140,124
Revenues:
External customers	$	19,236	$	522	$	55,552		$	51,892	$	887,847		$	1,015,049
Intersegment (c)	3,434		—		(2,751		)	4,056		(4,739		)	—
Total revenues of reportable segments	$	22,670	$	522	$	52,801		$	55,948	$	883,108		$	1,015,049
Six Months Ended June 30, 2015
Segment Margin (a)	$	28,686	$	50,298	$	39,381		$	52,918	$	21,405		$	192,688
Capital expenditures (b)	$	109,484	$	2,139	$	1,450		$	27,662	$	92,626		$	233,361
Revenues:
External customers	$	31,687	$	2,048	$	97,221		$	115,243	$	936,985		$	1,183,184
Intersegment (c)	6,314		—		(4,773		)	4,722		(6,263		)	—
Total revenues of reportable segments	$	38,001	$	2,048	$	92,448		$	119,965	$	930,722		$	1,183,184
Six Months Ended June 30, 2014
Segment Margin (a)	$	31,220	$	24,838	$	42,499		$	39,435	$	22,040		$	160,032
Capital expenditures (b)	$	27,741	$	13,576	$	899		$	48,036	$	152,650		$	242,902
Revenues:
External customers	$	34,739	$	1,469	$	112,659		$	102,982	$	1,782,919		$	2,034,768
Intersegment (c)	7,904		—		(5,665		)	9,259		(11,498		)	—
Total revenues of reportable segments	$	42,643	$	1,469	$	106,994		$	112,241	$	1,771,421		$	2,034,768

Total assets by reportable segment were as follows:



	June 30, 2015		December 31, 2014
Onshore pipeline transportation	$	516,365	$	460,012
Offshore pipeline transportation	631,998		645,668
Refinery services	394,794		403,703
Marine transportation	754,515		745,128
Supply and logistics	1,042,620		907,189
Other assets	63,989		68,674
Total consolidated assets	3,404,281		3,230,374


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

(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 $0.0 million and $1.8 million during the three and six months ended June 30, 2015 and $2.3 million and $12.7

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

million during the three and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Segment Margin	$	98,567		$	82,681		$	192,688		$	160,032
Corporate general and administrative expenses	(13,953		)	(13,789		)	(26,252		)	(24,850		)
Depreciation and amortization	(28,205		)	(20,491		)	(55,330		)	(39,771		)
Interest expense	(17,905		)	(14,069		)	(37,120		)	(26,873		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(7,038		)	(7,808		)	(17,421		)	(13,585		)
Non-cash items not included in Segment Margin	1,771			(3,043		)	(843		)	282
Cash payments from direct financing leases in excess of earnings	(1,405		)	(1,371		)	(2,767		)	(2,709		)
Loss on extinguishment of debt	(19,225		)	—			(19,225		)	—
Income tax expense	(942		)	(962		)	(1,850		)	(1,603		)
Net income	$	11,665		$	21,148		31,880			50,923


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

12. Transactions with Related Parties

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	806	$	713	$	1,505	$	1,368
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	150	$	360	$	300


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

Amount due from Related Party

At June 30, 2015 and December 31, 2014 Sandhill Group, LLC owed us $0.3 million, respectively, for purchases of CO₂.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2015			2014
(Increase) decrease in:
Accounts receivable	$	202		$	20,827
Inventories	(7,737		)	(44,523		)
Deferred charges	(7,725		)	—
Other current assets	2,286			47,542
Increase (decrease) in:
Accounts payable	(5,998		)	13,436
Accrued liabilities	(16,067		)	(43,971		)
Net changes in components of operating assets and liabilities	(35,039		)	(6,689		)

Payments of interest and commitment fees, net of amounts capitalized, were $40.3 million and $33.4 million for the six months ended June 30, 2015 and June 30, 2014, respectively. We capitalized interest of $7.2 million and $10.0 million during the six months ended June 30, 2015 and June 30, 2014.

At June 30, 2015 and June 30, 2014, we had incurred liabilities for fixed and intangible asset additions totaling $52.9 million and $42.1 million, respectively, that had not been paid at the end of the second quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

At June 30, 2015 we had incurred liabilities for other asset additions totaling $12.7 million, that had not been paid at the end of the second quarter and, therefore, were not included in the caption "Other, net" under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

14. 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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 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)	188			—
Weighted average contract price per bbl	$	57.50		$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	402			206
Weighted average contract price per bbl	$	60.72		$	62.87
Crude oil swaps:
Contract volumes (1,000 bbls)	170			—
Weighted average contract price per bbl	$	(2.11	)	$	—
Diesel futures:
Contract volumes (1,000 bbls)	80			20
Weighted average contract price per gal	$	1.89		$	1.87
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	360			5
Weighted average contract price per bbl	$	52.07		$	53.35
Crude oil options:
Contract volumes (1,000 bbls)	145			50
Weighted average premium received	$	1.08		$	0.27

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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at June 30, 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	June 30, 2015			December 31, 2014
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	363		$	16,383
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(363		)	(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	$	8		$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(8		)	—
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,366	)	$	(2,310	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,366			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⁾	$	(480	)	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	480			—
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—


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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of June 30, 2015, we had a net broker receivable of approximately $2.6 million (consisting of initial margin of $3.5 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 June 30, 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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended June 30,					Six Months Ended June 30,
		2015			2014		2015			2014
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	(4,021	)	$	—	$	(1,835	)	$	—
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	(4,209		)	727		(5,014		)	3,496
Total commodity derivatives		$	(8,230	)	$	727	$	(6,849	)	$	3,496

15. 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 June 30, 2015 and December 31, 2014.



	Fair Value at							Fair Value at
	June 30, 2015							December 31, 2014
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	371		$	—	$	—	$	16,383		$	—	$	—
Liabilities	$	(1,846	)	$	—	$	—	$	(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 14 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 June 30, 2015 our senior unsecured notes had a carrying value of $1.1 billion and a fair value of $1.1 billion, compared to $1.1 billion and $1.0 billion, respectively, at December 31, 2014. 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.

16. 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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

17. Condensed Consolidating Financial Information

Our $1.1 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 9 for additional information regarding our consolidated debt obligations.

During the second quarter of 2015, the Company took action related to certain non-guarantor subsidiaries that resulted in these subsidiaries previously categorized as non-guarantor subsidiaries becoming wholly owned guarantor subsidiaries. The changes made to guarantor subsidiaries did not impact the Company's previously reported consolidated net operating results, financial position, or cash flows. The condensed consolidating balance sheet as of December 31, 2014 and the condensed consolidating statements of operations for the three and six months ended June 30, 2014 as well as the condensed consolidating statements of cash flows for the six months ended June 30, 2014 have been retrospectively adjusted to reflect these updates to our guarantor subsidiaries as though the subsidiaries had been guarantors in all periods presented.

The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

June 30, 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	$	6	$	—	$	8,006		$	707		$	—		$	8,719
Other current assets	1,406,653		—		338,521			50,763			(1,444,886		)	351,051
Total current assets	1,406,659		—		346,527			51,470			(1,444,886		)	359,770
Fixed assets, at cost	—		—		2,045,180			75,466			—			2,120,646
Less: Accumulated depreciation	—		—		(286,734		)	(18,142		)	—			(304,876		)
Net fixed assets	—		—		1,758,446			57,324			—			1,815,770
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	29,677		—		267,482			143,627			(151,500		)	289,286
Equity investees	—		—		614,409			—			—			614,409
Investments in subsidiaries	1,602,824		—		100,279			—			(1,703,103		)	—
Total assets	$	3,039,160	$	—	$	3,412,189		$	252,421		$	(3,299,489	)	$	3,404,281
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	12,471	$	—	$	1,772,548		$	2,113		$	(1,445,014	)	$	342,118
Senior secured credit facility	585,200		—		—			—			—			585,200
Senior unsecured notes	1,100,000		—		—			—			—			1,100,000
Deferred tax liabilities	—		—		20,005			—			—			20,005
Other liabilities	—		—		15,470			151,331			(151,332		)	15,469
Total liabilities	1,697,671		—		1,808,023			153,444			(1,596,346		)	2,062,792
Partners’ capital	1,341,489		—		1,604,166			98,977			(1,703,143		)	1,341,489
Total liabilities and partners’ capital	$	3,039,160	$	—	$	3,412,189		$	252,421		$	(3,299,489	)	$	3,404,281

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	$	—	$	8,310		$	1,143		$	—		$	9,462
Other current assets	1,378,573		—		333,385			46,215			(1,412,269		)	345,904
Total current assets	1,378,582		—		341,695			47,358			(1,412,269		)	355,366
Fixed assets, at cost	—		—		1,823,556			75,502			—			1,899,058
Less: Accumulated depreciation	—		—		(251,171		)	(16,886		)	—			(268,057		)
Net fixed assets	—		—		1,572,385			58,616			—			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		—		97,195			—			(1,531,450		)	—
Total assets	$	2,841,258	$	—	$	3,234,353		$	252,674		$	(3,097,911	)	$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	11,016	$	—	$	1,761,856		$	2,705		$	(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	—		—		18,233			154,021			(154,021		)	18,233
Total liabilities	1,612,055		—		1,798,843			156,726			(1,566,453		)	2,001,171
Partners’ capital	1,229,203		—		1,435,510			95,948			(1,531,458		)	1,229,203
Total liabilities and partners’ capital	$	2,841,258	$	—	$	3,234,353		$	252,674		$	(3,097,911	)	$	3,230,374

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 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	$	—		$	—	$	14,378		$	5,813		$	—		$	20,191
Refinery services	—			—		45,272			5,859			(4,807		)	46,324
Marine transportation	—			—		62,594			—			—			62,594
Supply and logistics	—			—		529,073			(3,966		)	2,111			527,218
Total revenues	—			—		651,317			7,706			(2,696		)	656,327
COSTS AND EXPENSES:
Supply and logistics costs	—			—		517,230			(3,433		)	2,110			515,907
Marine transportation costs	—			—		35,286			—			—			35,286
Refinery services operating costs	—			—		25,081			5,526			(4,772		)	25,835
Pipeline transportation operating costs	—			—		6,974			(92		)	—			6,882
General and administrative	—			—		14,861			(29		)	—			14,832
Depreciation and amortization	—			—		28,249			(44		)	—			28,205
Total costs and expenses	—			—		627,681			1,928			(2,662		)	626,947
OPERATING INCOME	—			—		23,636			5,778			(34		)	29,380
Equity in earnings of subsidiaries	48,777			—		2,099			—			(50,876		)	—
Equity in earnings of equity investees	—			—		18,661			—			—			18,661
Interest (expense) income, net	(17,887		)	—		3,787			(3,805		)	—			(17,905		)
Other income/(expense), net	(19,225		)	—		1,696			—			—			(17,529		)
Income before income taxes	11,665			—		49,879			1,973			(50,910		)	12,607
Income tax benefit (expense)	—			—		(1,023		)	81			—			(942		)
NET INCOME	$	11,665		$	—	$	48,856		$	2,054		$	(50,910	)	$	11,665

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Pipeline transportation services	$	—		$	—	$	16,942		$	6,250		$	—		$	23,192
Refinery services	—			—		51,694			4,571			(3,464		)	52,801
Marine transportation	—			—		55,948			—			—			55,948
Supply and logistics	—			—		883,108			—			—			883,108
Total revenues	—			—		1,007,692			10,821			(3,464		)	1,015,049
COSTS AND EXPENSES:
Supply and logistics costs	—			—		872,169			—			—			872,169
Marine transportation costs	—			—		36,905			—			—			36,905
Refinery services operating costs	—			—		30,399			4,212			(3,463		)	31,148
Pipeline transportation operating costs	—			—		8,172			211			—			8,383
General and administrative	—			—		14,696			—			—			14,696
Depreciation and amortization	—			—		19,851			640			—			20,491
Total costs and expenses	—			—		982,192			5,063			(3,463		)	983,792
OPERATING INCOME	—			—		25,500			5,758			(1		)	31,257
Equity in earnings of subsidiaries	35,214			—		1,796			—			(37,010		)	—
Equity in earnings of equity investees	—			—		4,922			—			—			4,922
Interest (expense) income, net	(14,066		)	—		3,932			(3,935		)	—			(14,069		)
Income before income taxes	21,148			—		36,150			1,823			(37,011		)	22,110
Income tax expense	—			—		(890		)	(72		)	—			(962		)
NET INCOME	$	21,148		$	—	$	35,260		$	1,751		$	(37,011	)	$	21,148

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 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	$	—		$	—	$	27,792		$	12,257		$	—		$	40,049
Refinery services	—			—		90,591			7,971			(6,114		)	92,448
Marine transportation	—			—		119,965			—			—			119,965
Supply and logistics	—			—		930,722			—			—			930,722
Total revenues	—			—		1,169,070			20,228			(6,114		)	1,183,184
COSTS AND EXPENSES:
Supply and logistics costs	—			—		912,064			—			—			912,064
Marine transportation costs	—			—		66,880			—			—			66,880
Refinery services operating costs	—			—		51,300			7,645			(6,083		)	52,862
Pipeline transportation operating costs	—			—		13,455			341			—			13,796
General and administrative	—			—		28,053			—			—			28,053
Depreciation and amortization	—			—		54,045			1,285			—			55,330
Total costs and expenses	—			—		1,125,797			9,271			(6,083		)	1,128,985
OPERATING INCOME	—			—		43,273			10,957			(31		)	54,199
Equity in earnings of subsidiaries	88,184			—		3,486			—			(91,670		)	—
Equity in earnings of equity investees	—			—		34,180			—			—			34,180
Interest (expense) income, net	(37,079		)	—		7,601			(7,642		)	—			(37,120		)
Other income/(expense), net	(19,225		)	—		1,696			—			—			(17,529		)
Income before income taxes	31,880			—		90,236			3,315			(91,701		)	33,730
Income tax expense	—			—		(1,934		)	84			—			(1,850		)
NET INCOME	$	31,880		$	—	$	88,302		$	3,399		$	(91,701	)	$	31,880

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Pipeline transportation services	$	—		$	—	$	31,477		$	12,635		$	—		$	44,112
Refinery services	—			—		103,424			10,645			(7,075		)	106,994
Marine transportation	—			—		112,241			—			—			112,241
Supply and logistics	—			—		1,771,421			—			—			1,771,421
Total revenues	—			—		2,018,563			23,280			(7,075		)	2,034,768
COSTS AND EXPENSES:
Supply and logistics costs	—			—		1,748,749			—			—			1,748,749
Marine transportation costs	—			—		72,679			—			—			72,679
Refinery services operating costs	—			—		61,990			10,058			(7,705		)	64,343
Pipeline transportation operating costs	—			—		15,408			453			—			15,861
General and administrative	—			—		26,706			—			—			26,706
Depreciation and amortization	—			—		38,511			1,260			—			39,771
Total costs and expenses	—			—		1,964,043			11,771			(7,705		)	1,968,109
OPERATING INCOME	—			—		54,520			11,509			630			66,659
Equity in earnings of subsidiaries	77,793			—		3,572			—			(81,365		)	—
Equity in earnings of equity investees	—			—		12,740			—			—			12,740
Interest (expense) income, net	(26,870		)	—		7,898			(7,901		)	—			(26,873		)
Income before income taxes	50,923			—		78,730			3,608			(80,735		)	52,526
Income tax benefit (expense)	—			—		(1,477		)	(126		)	—			(1,603		)
NET INCOME	$	50,923		$	—	$	77,253		$	3,482		$	(80,735	)	$	50,923

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 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	$	(30,856	)	$	—	$	145,231		$	2,233		$	(45,506	)	$	71,102
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(240,646		)	—			—			(240,646		)
Cash distributions received from equity investees - return of investment	71,787			—		11,490			—			(71,787		)	11,490
Investments in equity investees	(197,722		)	—		(1,750		)	—			197,722			(1,750		)
Repayments on loan to non-guarantor subsidiary	—			—		2,692			—			(2,692		)	—
Proceeds from asset sales	—			—		2,228			—			—			2,228
Other, net	—			—		(729		)	—			—			(729		)
Net cash provided by (used) in investing activities	(125,935		)	—		(226,715		)	—			123,243			(229,407		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	550,500			—		—			—			—			550,500
Repayments on senior secured credit facility	(515,700		)	—		—			—			—			(515,700		)
Proceeds from issuance of senior unsecured notes	400,000			—		—			—			—			400,000
Repayment of senior unsecured notes	(350,000		)	—		—			—			—			(350,000		)
Debt issuance costs	(8,418		)	—		—			—			—			(8,418		)
Issuance of common units for cash, net	197,722			—		197,722			—			(197,722		)	197,722
Distributions to partners/owners	(117,316		)	—		(117,316		)	—			117,316			(117,316		)
Other, net	—			—		774			(2,669		)	2,669			774
Net cash provided by (used in) financing activities	156,788			—		81,180			(2,669		)	(77,737		)	157,562
Net (decrease) increase in cash and cash equivalents	(3		)	—		(304		)	(436		)	—			(743		)
Cash and cash equivalents at beginning of period	9			—		8,310			1,143			—			9,462
Cash and cash equivalents at end of period	$	6		$	—	$	8,006		$	707		$	—		$	8,719

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash (used in) provided by operating activities	$	(175,807	)	$	—	$	351,163		$	2,672		$	(72,831	)	$	105,197
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(240,994		)	—			—			(240,994		)
Cash distributions received from equity investees - return of investment	23,385			—		6,173			—			(23,385		)	6,173
Investments in equity investees	—			—		(14,826		)	—			—			(14,826		)
Repayments on loan to non-guarantor subsidiary	—			—		2,433			—			(2,433		)	—
Proceeds from asset sales	—			—		133			—			—			133
Other, net	—			—		(2,635		)	—			—			(2,635		)
Net cash used in investing activities	23,385			—		(249,716		)	—			(25,818		)	(252,149		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,181,200			—		—			—			—			1,181,200
Repayments on senior secured credit facility	(1,271,800		)	—		—			—			—			(1,271,800		)
Proceeds from issuance of senior unsecured notes	350,000			—		—			—			—			350,000
Debt issuance costs	(10,752		)	—		—			—			—			(10,752		)
Issuance of common units for cash, net	—			—		—			—			—			—
Distributions to partners/owners	(96,236		)	—		(96,236		)	—			96,236			(96,236		)
Other, net	—			—		—			(2,413		)	2,413			—
Net cash provided by (used in) financing activities	152,412			—		(96,236		)	(2,413		)	98,649			152,412
Net (decrease) increase in cash and cash equivalents	(10		)	—		5,211			259			—			5,460
Cash and cash equivalents at beginning of period	20			—		8,050			796			—			8,866
Cash and cash equivalents at end of period	$	10		$	—	$	13,261		$	1,055		$	—		$	14,326

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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 $11.7 million, or $0.12 per common unit, during the three months ended June 30, 2015 (“2015 Quarter”) compared to net income of $21.1 million or $0.24 per common unit, during the three months ended June 30, 2014 (“2014 Quarter”).

Available Cash before Reserves was $68.8 million for the 2015 Quarter, an increase of $13.3 million, or 24%, from the 2014 Quarter. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin (as described below in “Financial Measures”) was $98.6 million for the 2015 Quarter, an increase of $15.9 million, or 19%, from the 2014 Quarter.

The increase in our Segment Margin resulted primarily from increases attributable to our offshore pipeline transportation and marine transportation segments of $13.7 million, and $8.2 million, respectively. These increases, as discussed in more detail below and partially offset by smaller decreases in onshore pipeline transportation, refinery services and supply and logistics 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 recently acquired and constructed assets. In addition, we recognized a $19.2 million loss on debt extinguishment during the 2015 Quarter, relating to the early retirement of our $350 million 7.875% senior unsecured notes due 2018.

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

Distribution Increase

In July 2015, we declared our fortieth consecutive increase in our quarterly distribution to our common unitholders. Thirty-five of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In August 2015, we will pay a distribution of $0.625 per unit representing a 10.6% increase from our distribution of $0.565 per unit related to the second quarter of 2014.

Acquisition of Offshore Pipelines and Services Business of Enterprise Products Operating, LLC

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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.

Financial Measure Reconciliation

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 June 30,
	2015			2014
	(in thousands)
Net income	$	11,665		$	21,148
Depreciation and amortization	28,205			20,491
Cash received from direct financing leases not included in income	1,405			1,371
Cash effects of sales of certain assets	460			61
Effects of distributable cash generated by equity method investees not included in income	7,038			7,808
Cash effects of legacy stock appreciation rights plan	(91		)	(127		)
Non-cash legacy stock appreciation rights plan expense	(468		)	322
Expenses related to acquiring or constructing growth capital assets	1,992			418
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value	290			2,724
Maintenance capital utilized	(746		)	(178		)
Non-cash tax expense	642			512
Loss on debt extinguishment	19,225			—
Other items, net	(831		)	942
Available Cash before Reserves	$	68,786		$	55,492

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2015 Quarter decreased $358.7 million, or 35%, from the 2014 Quarter. Additionally, our costs and expenses decreased $356.8 million, or 36%, between the two periods.

The substantial majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant decrease in our revenues and costs between the two second quarter periods is primarily attributable to 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 44% to $57.94 per barrel in the second quarter of 2015, as compared to $103.00 per barrel in the second quarter of 2014.

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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.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2015 and June 30, 2014 was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
Onshore pipeline transportation	$	14,363	$	16,531	$	28,686	$	31,220
Offshore pipeline transportation	25,100		11,435		50,298		24,838
Refinery services	20,221		21,627		39,381		42,499
Marine transportation	27,225		18,978		52,918		39,435
Supply and logistics	11,658		14,110		21,405		22,040
Total Segment Margin	$	98,567	$	82,681	$	192,688	$	160,032

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Segment Margin	$	98,567		$	82,681		$	192,688		$	160,032
Corporate general and administrative expenses	(13,953		)	(13,789		)	(26,252		)	(24,850		)
Depreciation and amortization	(28,205		)	(20,491		)	(55,330		)	(39,771		)
Interest expense	(17,905		)	(14,069		)	(37,120		)	(26,873		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(7,038		)	(7,808		)	(17,421		)	(13,585		)
Non-cash items not included in Segment Margin	1,771			(3,043		)	(843		)	282
Cash payments from direct financing leases in excess of earnings	(1,405		)	(1,371		)	(2,767		)	(2,709		)
Loss on debt extinguishment	(19,225		)	—			(19,225		)	—
Income tax expense	(942		)	(962		)	(1,850		)	(1,603		)
Net income	$	11,665		$	21,148		$	31,880		$	50,923

(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

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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.

Onshore Pipeline Transportation Segment

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	10,195		$	10,643		$	20,538		$	20,888
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	6,113			6,367			12,476			12,874
Sales of onshore crude oil pipeline loss allowance volumes	1,538			3,645			2,603			4,855
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(5,135		)	(5,777		)	(10,205		)	(10,647		)
Payments received under direct financing leases not included in income	1,405			1,371			2,767			2,709
Other	247			282			507			541
Segment Margin	$	14,363		$	16,531		$	28,686		$	31,220

Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	68,407			60,662			71,903			54,769
Jay	18,082			24,337			16,784			26,085
Mississippi	16,824			15,121			15,882			15,150
Louisiana ⁽¹⁾	10,178			22,435			19,975			13,574
Onshore crude oil pipelines total	113,491			122,555			124,544			109,578

CO₂ pipeline (average Mcf/day):
Free State	167,451			178,500			178,915			185,010

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

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Three Months Ended June 30, 2015 Compared with Three Months Ended June 30, 2014

Onshore Pipeline Transportation Segment Margin for the 2015 Quarter decreased $2.2 million, or 13%. The significant components and details of this change were as follows:


•	Onshore crude oil pipeline loss allowance volumes, collected and sold, resulted in a decrease in segment margin quarter over quarter of $2.1 million. This decrease is primarily due to the change in the market price of crude oil between the respective periods. 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 decreased slightly by $0.4 million quarter to quarter, primarily due to a net decrease in throughput volumes of 9,064 barrels per day. This was primarily the result of decreased volumes on our Jay and Louisiana pipeline systems. These decreases were partially offset by volume variances on our other onshore pipeline systems. 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. As our Baton Rouge growth projects become completed and operational, we anticipate a ramp up in volumes on our Louisiana pipeline system in future periods.

•

Although volumes on our Free State CO₂ pipeline system decreased 11,049 Mcf per day, or 6%, 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 above a base level on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Onshore Pipeline Transportation Segment Margin for the first six months of 2015 decreased $2.5 million, or 8%. The significant components and details of this change were as follows:


•	Onshore crude oil pipeline loss allowance volumes, collected and sold, resulted in a decrease in segment margin quarter over quarter of $2.3 million. This decrease is primarily due to the change in the market price of crude oil between the respective periods. 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 decreased slightly by $0.4 million quarter to quarter, despite an overall net increase in throughput volumes of 14,966 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.

•

Although volumes on our Free State CO₂ pipeline system decreased 6,095 Mcf per day, or 3%, in the first six months of 2015 as compared to the first six months of 2014, 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 above a base level 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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
Offshore Pipeline Transportation Segment Margin⁽¹⁾	$	25,100	$	11,435	$	50,298	$	24,838

Volumetric Data 100% basis (average barrels/day unless otherwise noted):
Offshore crude oil pipelines:
CHOPS	166,735		169,371		169,382		180,288
Poseidon	274,517		201,190		251,913		206,074
Odyssey	51,165		40,492		49,872		42,735
GOPL ⁽²⁾	18,709		4,197		12,493		5,814
SEKCO⁽³⁾	70,422		—		46,265		—
Offshore crude oil pipelines total	581,548		415,250		529,925		434,911

Volumetric Data net to our ownership interest (average barrels/day unless otherwise noted):
Offshore crude oil pipelines:
CHOPS	83,368		84,686		84,691		90,144
Poseidon	76,865		56,333		70,536		57,701
Odyssey	14,838		11,743		14,463		12,393
GOPL ⁽²⁾	18,709		4,197		12,493		5,814
SEKCO ⁽³⁾	35,211		—		23,133		—
Offshore crude oil pipelines total	228,991		156,959		205,316		166,052

(1)

Offshore Pipeline Transportation segment margin includes approximately $25 million and $50 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting for the three months and six months ended June 30, 2015, respectively. Segment Margin for the three months and six months ended June 30, 2014 include $12 million and $25 million in similar distributions from our offshore pipeline joint ventures, respectively.


(2)	Includes 100% of our undivided joint interest ownership in GOPL.


(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 six months ended June 30, 2015 for SEKCO reflect the gradual commencement of throughput beginning in January of 2015.

Three Months Ended June 30, 2015 Compared with Three Months Ended June 30, 2014

Offshore Pipeline Transportation Segment Margin for the 2015 Quarter increased $13.7 million, or 120%, from the 2014 Quarter. 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 did not exceed a level at which throughput revenues would exceed the monthly minimum payments until the midpoint of the 2015 Quarter. Our SEKCO pipeline is connected to our Poseidon pipeline, so increases in throughput volumes on our SEKCO pipeline have a similar impact on throughput volumes on our Poseidon pipeline. Volume variances on our offshore pipeline systems excluding SEKCO and Poseidon largely offset each other.

Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Offshore Pipeline Transportation Segment Margin for the first six months of 2015 increased $25.5 million, or 103%, from the first six months of 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 did not exceed a level at which throughput

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revenues would exceed the monthly minimum payments until the midpoint of the 2015 Quarter. Our SEKCO pipeline is connected to our Poseidon pipeline, so increases in throughput volumes on our SEKCO pipeline have a similar impact on throughput volumes on our Poseidon pipeline. Volume variances on our offshore pipeline systems excluding SEKCO and Poseidon largely offset each other.

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Volumes sold (in Dry short tons "DST"):
NaHS volumes	32,503			37,607			64,933			78,509
NaOH (caustic soda) volumes	22,130			24,066			43,316			48,099
Total	54,633			61,673			108,249			126,608

Revenues (in thousands):
NaHS revenues	$	36,082		$	41,162		$	71,535		$	84,270
NaOH (caustic soda) revenues	11,014			12,642			21,888			24,787
Other revenues	1,690			1,748			3,798			3,602
Total external segment revenues	$	48,786		$	55,552		$	97,221		$	112,659

Segment Margin (in thousands)	$	20,221		$	21,627		$	39,381		$	42,499

Average index price for NaOH per DST ⁽¹⁾	$	577		$	595		$	583		$	587
Raw material and processing costs as % of segment revenues	42		%	42		%	42		%	43		%

(1) Source: IHS Chemical

Three Months Ended June 30, 2015 Compared with Three Months Ended June 30, 2014

Refinery services Segment Margin for the 2015 Quarter decreased $1.4 million, or 7%. The significant components and details of this change were as follows:

•

NaHS revenues decreased 12% due primarily to a decrease in volumes. That decrease primarily resulted from lower total volumes than the 2014 Quarter attributable to the bankruptcy of one mining customer, reduced sales to a major customer as they work through an atypical ore seam as a result of a landslide, and certain sales foregone as a result of supply interruptions at one of our major processing facilities.


•	We were able to realize benefits from our favorable management of the purchasing (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 13% primarily 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.

•

Average index prices for caustic soda decreased to $577 per DST in the 2015 Quarter compared to $595 per DST during the 2014 Quarter. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

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Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Refinery services Segment Margin for the first six months of 2015 decreased $3.1 million, or 7%. The significant components and details of this change were as follows:

•

NaHS revenues decreased 15% primarily due to a decrease in volumes. That decrease primarily resulted from lower total volumes than the year earlier period attributable to the bankruptcy of one mining customer, reduced sales to a major customer as they work through an atypical ore seam as a result of a landslide, and certain sales foregone as a result of supply interruptions at one of our major processing facilities. Additionally, timing of certain bulk deliveries to our South American customers was a factor in decreased volumes for the six months ended between June 30, 2015 and June 30, 2014.


•	We were able to realize benefits from our favorable management of the purchasing (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 12% 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.

•

Average index prices for caustic soda decreased to $583 per DST in the first six months of 2015 compared to $587 per DST during the first six months 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 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, 36 push/tow boats (27 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues (in thousands):
Inland freight revenues	$	24,612		$	22,574		$	47,997		$	44,297
Offshore freight revenues	25,670			18,805			50,278			38,761
Other rebill revenues ⁽¹⁾	12,312			14,569			21,690			29,183
Total segment revenues	$	62,594		$	55,948		$	119,965		$	112,241

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	35,369		$	36,970		$	67,047		$	72,806

Segment Margin (in thousands)	$	27,225		$	18,978		$	52,918		$	39,435

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	99.4		%	97.4		%	97.8		%	98.0		%
Offshore Barge Utilization	99.7		%	99.8		%	99.8		%	99.9		%

(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.

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Three Months Ended June 30, 2015 Compared with Three Months Ended June 30, 2014

Marine Transportation Segment Margin for the 2015 Quarter increased $8.2 million, or 43%, from the 2014 Quarter. This increase in Segment Margin in 2015 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, two additional barges added to our inland fleet, and higher realized contract rates on several of our oceangoing barges.

Utilization rates on 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.

Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Marine Transportation Segment Margin for the first six months of 2015 increased $13.5 million, or 34%, from the first six months of 2014. This increase in Segment Margin in 2015 is primarily due to two full quarters of operating results from the M/T American Phoenix (included as part of our offshore marine fleet), which we acquired in November 2014, two additional barges added to our inland fleet, and higher realized contract rates on several of our oceangoing barges.

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;


•	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. 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.

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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.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Supply and logistics revenue	$	527,218		$	883,108		$	930,722		$	1,771,421
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(491,836		)	(841,547		)	(860,691		)	(1,694,589		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(23,926		)	(27,658		)	(48,835		)	(54,594		)
Other	202			207			209			(198		)
Segment Margin	$	11,658		$	14,110		$	21,405		$	22,040

Volumetric Data (average barrels per day):
Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	100,054			96,443			97,148			98,631
Rail load/unload volumes ⁽¹⁾	18,709			28,356			17,067			27,488

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

Three Months Ended June 30, 2015 Compared with Three Months Ended June 30, 2014

Segment Margin for our supply and logistics segment decreased by $2.5 million, or 17% between the two three month periods.

In the 2015 Quarter, the decrease in our Segment Margin is primarily due to lower crude oil volumes unloaded at our Natchez Terminal and our Port Hudson terminal relative to the 2014 Quarter, as we prepare for the increased utilization of different components of our Baton Rouge facilities.

Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Segment Margin for our supply and logistics segment decreased by $0.6 million, or 3% between the first six months of 2015 and the first six months of 2014.

In the six months ended June 30, 2015, the decrease in our Segment Margin is primarily due to lower crude oil volumes unloaded at our Natchez Terminal and our Port Hudson terminal relative to the 2014 quarter, as we prepare for the increased utilization of different components of our Baton Rouge facilities. These decreases were partially offset by 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.

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Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	10,643	$	11,147	$	20,314	$	18,897
Segment	874		892		1,779		1,822
Equity-based compensation plan expense	1,323		2,239		3,551		4,785
Third party costs related to business development activities and growth projects	1,992		418		2,409		1,202
Total general and administrative expenses	$	14,832	$	14,696	$	28,053	$	26,706

Total general and administrative expenses increased $0.1 million and $1.3 million between the three and six month periods primarily due to higher third party costs related to business development and growth activities.

Depreciation and amortization expense



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
Depreciation expense	$	22,512	$	16,409	$	44,549	$	31,686
Amortization of intangible assets	4,154		3,147		8,191		6,292
Amortization of CO2 volumetric production payments	1,539		935		2,590		1,793
Total depreciation and amortization expense	$	28,205	$	20,491	$	55,330	$	39,771

Total depreciation and amortization expense increased $7.7 million and $15.6 million between the three and six month periods primarily as a result of placing recently acquired and constructed assets in service during calendar 2014 and the first six months of 2015. Depreciation expense increased $6.1 million and $12.9 million between the three and six 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 $1.0 million and $1.9 million between the three and six 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	4,019		$	4,344		$	8,166		$	8,172
Interest expense, senior unsecured notes	16,718			14,437			33,562			26,359
Amortization of debt issuance costs and premium	1,303			1,216			2,550			2,320
Capitalized interest	(4,135		)	(5,928		)	(7,158		)	(9,978		)
Net interest expense	$	17,905		$	14,069		$	37,120		$	26,873

Net interest expense increased $3.8 million and $10.2 million between the three and six month periods primarily due to an increase in our average outstanding indebtedness from recently 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 $1.8 million and $2.8 million over the three and six 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.

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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 2015 Quarter included an unrealized gain on derivative positions, excluding fair value hedges, of $0.2 million. Net income for the 2014 Quarter included an unrealized loss on derivative positions of $2.7 million. Net income for the six months ended June 30, 2015 included an unrealized loss on derivative positions of $1.3 million. Net income for the same period in 2014 included an unrealized gain on derivative positions of $1.2 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.

The three and six months ended June 30, 2015, included a loss of approximately $19.2 million that was recognized in relation to the early retirement of our $350 million, 7.875% senior unsecured notes.

Liquidity and Capital Resources

General

As of June 30, 2015, we had $384.2 million of borrowing capacity available under our $1 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.

Our primary cash requirements consist of:


•	Working capital, primarily inventories;


•	Routine operating expenses;


•	Capital growth and maintenance projects;


•	Acquisitions of assets or businesses;


•	Payments related to servicing outstanding debt; and


•	Quarterly cash distributions to our unitholders.

Capital Resources

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

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 used 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.

On May 21, 2015, we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes at face value. Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Those notes mature on May 15, 2023. We used a portion of the proceeds from those notes to redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018. During May 2015, $300.1 million of the $350 million notes outstanding were tendered through the commencement of a cash tender offer. We recognized a loss of approximately $16.7 million in conjunction with the cash tender offer. On June, 20, 2015, the remaining $49.9 million outstanding of the $350 million were redeemed in full and a loss of approximately $2.5 million was recognized due to the early redemption.

At June 30, 2015, long-term debt totaled $1.7 billion, consisting of $585.2 million outstanding under our credit facility (including $43.4 million borrowed under the inventory sublimit tranche), a $350 million carrying amount of senior unsecured

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notes due on February 15, 2021, a $400 million carrying amount of senior unsecured notes due on May 15, 2023 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 13 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the six months ended June 30, 2015 and June 30, 2014.

The decrease in operating cash flow for the six months ended June 30, 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 six months ended June 30, 2015 were $71.1 million compared to $105.2 million for the six months ended June 30, 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.

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Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, business and other asset acquisitions for the six months ended June 30, 2015 and June 30, 2014 is as follows:



	Six Months Ended June 30,
	2015		2014
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Onshore pipeline transportation assets	$	2,776	$	1,119
Offshore pipeline transportation assets	389		900
Refinery services assets	1,411		409
Marine transportation assets	18,968		1,800
Supply and logistics assets	5,206		115
Information technology systems	175		—
Total maintenance capital expenditures	28,925		4,343
Growth capital expenditures:
Onshore pipeline transportation assets	106,708		26,622
Refinery services assets	39		490
Marine transportation assets	8,694		46,236
Supply and logistics assets	87,420		152,535
Information technology systems	906		358
Total growth capital expenditures	203,767		226,241
Total capital expenditures for fixed and intangible assets	232,692		230,584
Capital expenditures related to equity investees ⁽¹⁾	1,750		12,676
Total capital expenditures	$	234,442	$	243,260

(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 $580 million in 2015 and in future periods, inclusive of expenditures incurred through June 30, 2015. We anticipate that approximately $320 million of that total will be spent in 2015, inclusive of expenditures incurred through June 30, 2015. The most significant of these projects currently under construction are described below.

Wyoming Crude Oil Pipeline

We are constructing a new 60 mile crude oil pipeline to transport crude oil from new receipt point stations in Campbell County and Converse County, Wyoming to our existing Pronghorn Rail Facility. This new crude oil pipeline will have an initial capacity of approximately 30,000 barrels per day and will be supplied by truck volumes and third party gathering infrastructure in the Powder River Basin. We expect this pipeline to become operational in the third quarter of 2015.

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 in the second half of 2015.

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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 20 new-build barges and 14 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of 8 of those barges and 2 of those push boats through December 31, 2014. We accepted delivery of 3 additional push boats in the first half of 2015. We expect to take delivery of those remaining vessels periodically into 2016.

Growth Capital for Acquisition of Enterprise Offshore Pipelines and Services Business

In July 2015, we acquired the offshore pipeline and services business of Enterprise Products Operating, LLC and its affiliates for approximately $1.5 billion. That business includes approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms that serve some of the most active drilling and development regions in the United States, including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. At the closing of that transaction, we entered into a transition service agreement with affiliates of Enterprise to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. That acquisition complements and substantially expands our existing offshore pipelines segment. We expect it to be immediately accretive to Segment Margin and Available Cash before Reserves.

Maintenance Capital Expenditures

Our increase in maintenance capital expenditures for the six months ended June 30, 2015 primarily relates to construction and new marine push boats to replace older boats. For the six months ended June 30, 2015 we spent approximately $9 million on the construction of those replacement push boats. As we place more assets into service, particularly 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 August 14, 2015, we will pay a distribution of $0.625 per common unit totaling $68.7 million with respect to the second quarter of 2015 to common unitholders of record on July 31, 2015 inclusive of the holders of units issued on April 10, 2015, as well as those issued on July 22, 2015. This is the fortieth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 10 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 11 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

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Available Cash before Reserves

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 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 (includes distributions attributable to the quarter and received during or promptly following such quarter), 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.

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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 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.

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Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 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 current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:


•	demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, NaHS, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;


•	throughput levels and rates;


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


•	our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;


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


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


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


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


•	the effects of production declines and the effects of future laws and government regulation;


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


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


•	loss of key personnel;


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


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


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


•	our financial and commodity hedging arrangements


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


•	natural disasters, accidents or terrorism;

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•	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.

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 14 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

Except as described below, 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 and Form 8-K/A. On July 16, 2015, we filed a Current Report on Form 8-K that, among other things, revised, clarified and supplemented our risk factors, including those contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the "Annual Report") as set forth below.

As part of the filing of this Form 10-Q, we intend to revise, clarify and supplement our risk factors, including those contained in the Annual Report. The risk factors below should be considered together with the other risk factors described in the Annual Report and filings with the SEC under the Securities Exchange Act of 1934, as amended, after the Annual Report. 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.

As a result of the additional indebtedness incurred to consummate the Enterprise Offshore Business Acquisition, we may experience a potential material adverse effect on our financial condition and results of operations.

We financed the Enterprise Offshore Business Acquisition with the net proceeds from debt or equity financing and borrowings under our revolving credit facility.

Our increased indebtedness could also have adverse consequences on our business, such as:


•	requiring us to use a substantial portion of our cash flow from operations to service our indebtedness, which would reduce the available cash flow to fund working capital, capital expenditures, development projects and other general partnership purposes and reduce cash available for distributions;


•	limiting our ability to obtain additional financing to fund our working capital needs, acquisition, capital expenditures or other debt service requirements or for other purposes;


•	increasing the costs of incurring additional debt;


•	limiting our ability to compete with other companies that are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;


•	restricting the way in which we conduct our business because of financial and operating covenants in the agreements governing our existing and future indebtedness;


•	exposing us to potential events of default (if not cured or waived) under covenants contained in our debt instruments that could have a material adverse effect on our business, financial condition and operating results; and


•	limiting our ability to react to changing market conditions in our industry

The impact of any of these potential adverse consequences could have a material adverse effect on our results of operations, financial condition and liquidity.

As a result of the Enterprise Offshore Business Acquisition, we anticipate that the scope and size of our operations and business will substantially change. We cannot provide assurance that our expansion in scope and size will be successful.

We anticipate that the Enterprise Offshore Business Acquisition will substantially expand the scope and size of our business by adding substantial offshore operations to our existing offshore business. The anticipated future growth of our business will impose significant added responsibilities on management, including the need to identify, recruit, train and integrate additional employees. Our senior management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in the Enterprise Offshore Business Acquisition. Our ability to manage our business and growth will require us to continue to improve our operational, financial and management controls, reporting systems and procedures. We may also encounter risks, costs and expenses associated with any undisclosed or other unanticipated liabilities and use more cash and other financial resources on integration and implementation activities than we expect. We may not be able to successfully integrate the Enterprise Offshore Business into our existing operations or realize the expected economic

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benefits of the Enterprise Offshore Business Acquisition, which may have a material adverse effect on our business, financial condition and results of operations, including our distributable cash flow.

Failure to successfully combine our business with the assets acquired in the Enterprise Offshore Business Acquisition, or an inaccurate estimate by us of the benefits to be realized from the Enterprise Offshore Business Acquisition, may adversely affect our future results.

The Enterprise Offshore Business Acquisition involves potential risks, including:


•	the failure to realize expected profitability, growth or accretion;


•	environmental or regulatory compliance matters or liabilities;


•	title or permit issues;


•	the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and


•	the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate

The expected benefits from the Enterprise Offshore Business Acquisition may not be realized if our estimates of the potential net cash flows associated with the assets acquired by us in the Enterprise Offshore Business Acquisition are materially inaccurate or if we failed to identify operating issues or liabilities associated with the assets. The accuracy of our estimates of the potential net cash flows attributable to such assets is inherently uncertain.

If any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Enterprise Offshore Business Acquisition may not be fully realized, if at all, and our future financial condition, results of operations and distributable cash flow could be negatively impacted.

The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us and change the character or treatment of portions of our income. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships.

On May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations (the “Proposed Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations. The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income, we believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Code. If the regulations in their final form were to treat any material portion of our income we treat as qualifying income as non-qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely affecting the value of our common units.

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

None.

Item 3. Defaults Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits.

(a) Exhibits



	2.1	Purchase and Sale Agreement, dated July 16, 2015, by and between Genesis Energy, L.P. and Enterprise Products Operating, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K/A dated July 16, 2015, File No. 001-12295).
	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).
	4.2	Indenture, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K dated May 21, 2015, File No. 001-12295).
	4.3	Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (including the form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K dated May 21, 2015, File No. 001-12295).
*	4.4	Second Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.5	Third Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.6	Seventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.7	Eighth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.8	Eighth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.9	Ninth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
	4.10	Fourth Supplemental Indenture for 6.75% Senior Notes due 2022, dated as of July 23, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K dated July 28, 2015, File No. 001-12295)

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



*	Filed herewith

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SIGNATURES

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



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

	By:	GENESIS ENERGY, LLC, as General Partner



Date:	July 29, 2015	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer