GENESIS ENERGY LP - Quarter Report: 2014 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2014

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)



Delaware	76-0513049
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

919 Milam, Suite 2100, Houston, TX	77002
(Address of principal executive offices)	(Zip code)
Registrant’s telephone number, including area code: (713) 860-2500

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 93,250,988 Class A Common Units and 39,997 Class B Common Units outstanding as of October 30, 2014.

Table of Contents

GENESIS ENERGY, L.P.

TABLE OF CONTENTS

Insert Title Here

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Partners’ Capital	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
	1. Organization and Basis of Presentation and Consolidation	7
	2. Recent Accounting Developments	7
	3. Acquisition and Divestiture	8
	4. Inventories	9
	5. Fixed Assets	10
	6. Equity Investees	10
	7. Intangible Assets	11
	8. Debt	12
	9. Partners' Capital and Distributions	13
	10. Business Segment Information	14
	11. Transactions with Related Parties	15
	12. Supplemental Cash Flow Information	16
	13. Derivatives	16
	14. Fair-Value Measurements	19
	15. Contingencies	19
	16. Subsequent Event	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	44
Item 4.	Controls and Procedures	44
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	47
SIGNATURES		48

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)



	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16,925		$	8,866
Accounts receivable - trade, net	323,535			368,033
Inventories	99,390			85,330
Other	29,457			72,994
Total current assets	469,307			535,223
FIXED ASSETS, at cost	1,668,131			1,327,974
Less: Accumulated depreciation	(248,145		)	(199,230		)
Net fixed assets	1,419,986			1,128,744
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	147,424			151,903
EQUITY INVESTEES	639,047			620,247
INTANGIBLE ASSETS, net of amortization	54,446			62,928
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	57,356			38,111
TOTAL ASSETS	$	3,112,612		$	2,862,202
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	299,621		$	316,204
Accrued liabilities	134,276			130,349
Total current liabilities	433,897			446,553
SENIOR SECURED CREDIT FACILITY	335,000			582,800
SENIOR UNSECURED NOTES	1,050,673			700,772
DEFERRED TAX LIABILITIES	17,178			15,944
OTHER LONG-TERM LIABILITIES	18,831			18,396
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 93,290,985 and 88,690,985 units issued and outstanding at September 30, 2014 and December 31, 2013, respectively	1,257,033			1,097,737
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	3,112,612		$	2,862,202

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUES:
Supply and logistics	$	891,583		$	1,014,666		$	2,775,245		$	2,953,892
Refinery services	51,208			52,410			158,202			153,370
Pipeline transportation services	21,323			23,217			65,435			66,533
Total revenues	964,114			1,090,293			2,998,882			3,173,795
COSTS AND EXPENSES:
Supply and logistics product costs	791,411			948,332			2,485,068			2,740,887
Supply and logistics operating costs	62,298			50,528			190,069			145,149
Refinery services operating costs	29,031			33,040			93,374			98,304
Pipeline transportation operating costs	7,193			6,278			23,054			20,507
General and administrative	13,765			11,959			40,471			34,712
Depreciation and amortization	25,148			16,066			64,919			46,780
Total costs and expenses	928,846			1,066,203			2,896,955			3,086,339
OPERATING INCOME	35,268			24,090			101,927			87,456
Equity in earnings of equity investees	15,017			7,059			27,757			16,618
Interest expense	(20,441		)	(12,587		)	(47,314		)	(36,283		)
Income from continuing operations before income taxes	29,844			18,562			82,370			67,791
Income tax expense	(731		)	(596		)	(2,334		)	(510		)
Income from continuing operations	29,113			17,966			80,036			67,281
Income from discontinued operations	—			508			—			941
NET INCOME	$	29,113		$	18,474		$	80,036		$	68,222
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
Continuing operations	$	0.33		$	0.21		$	0.90		$	0.82
Discontinued operations	—			0.01			—			0.01
Net income per common unit	$	0.33		$	0.22		$	0.90		$	0.83
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	88,941			83,878			88,775			82,361

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Number of Common Units		Partners’ Capital
	2014	2013	2014			2013
Partners’ capital, January 1	88,691	81,203	$	1,097,737		$	916,495
Net income	—	—	80,036			68,222
Cash distributions	—	—	(146,350		)	(122,097		)
Issuance of common units for cash, net	4,600	5,750	225,610			263,597
Conversion of waiver units	—	1,738	—			—
Partners' capital, September 30	93,291	88,691	$	1,257,033		$	1,126,217

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	80,036		$	68,222
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	64,919			46,789
Amortization of debt issuance costs and premium	3,541			3,234
Amortization of unearned income and initial direct costs on direct financing leases	(11,833		)	(12,160		)
Payments received under direct financing leases	15,946			15,946
Equity in earnings of investments in equity investees	(27,757		)	(16,618		)
Cash distributions of earnings of equity investees	38,031			24,352
Non-cash effect of equity-based compensation plans	7,624			10,579
Deferred and other tax liabilities (benefits)	1,234			(186		)
Unrealized gains on derivative transactions	(5,680		)	(2,802		)
Other, net	3,008			336
Net changes in components of operating assets and liabilities (Note 12)	39,050			(28,354		)
Net cash provided by operating activities	208,119			109,338
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(336,061		)	(199,634		)
Cash distributions received from equity investees - return of investment	11,352			8,272
Investments in equity investees	(40,426		)	(71,443		)
Acquisitions	—			(230,921		)
Proceeds from asset sales	178			810
Other, net	(4,706		)	(1,004		)
Net cash used in investing activities	(369,663		)	(493,920		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,420,900			1,234,500
Repayments on senior secured credit facility	(1,668,700		)	(1,323,200		)
Proceeds from issuance of senior unsecured notes	350,000			350,000
Debt issuance costs	(11,857		)	(8,157		)
Issuance of common units for cash, net	225,610			263,597
Distributions to common unitholders	(146,350		)	(122,097		)
Other, net	—			(4,484		)
Net cash provided by financing activities	169,603			390,159
Net increase in cash and cash equivalents	8,059			5,577
Cash and cash equivalents at beginning of period	8,866			11,282
Cash and cash equivalents at end of period	$	16,925		$	16,859

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

Table of Contents

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 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 customers, operations and assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We manage our businesses through the following three divisions that constitute our reportable segments:


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


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


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

Basis of Presentation and Consolidation

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

Our results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The Condensed Consolidated Financial Statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.

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

2. Recent Accounting Developments

Recently Issued

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

Table of Contents

3. Acquisition and Divestiture

Acquisition

Offshore Marine Transportation Business

In August 2013, we completed the acquisition of substantially all of the assets of the downstream transportation business of Hornbeck Offshore Services, Inc. for $230.9 million, which we refer to as our offshore marine transportation business and assets. The total acquisition cost has been allocated to fixed assets based on fair values. Such fair values were developed by management. The acquired business was primarily comprised of nine barges and nine tug boats which transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. That acquisition complements and further integrates our existing operations, including our Genesis Marine inland barge business (comprised of 62 barges and 22 push/tow boats), our crude oil and heavy refined products storage and blending terminals as well as our crude oil pipeline systems. That acquisition was funded with proceeds from our $1 billion revolving credit facility. We have reflected the financial results of the acquired business in our supply and logistics segment from the date of the acquisition.

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



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
Revenues	$	8,651	$	8,651
Net income	$	2,520	$	2,520

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



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
Pro forma earnings data:
Revenues	$	1,101,676	$	3,216,680
Net income	$	24,294	$	81,780

Table of Contents

Divestiture

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



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
Revenues	$	169,526	$	446,894
Cost and expenses	169,018		445,954
Operating income	508		940
Interest income	—		1
Income from discontinued operations	$	508	$	941

4. Inventories

The major components of inventories were as follows:



	September 30, 2014		December 31, 2013
Petroleum products	$	71,353	$	71,373
Crude oil	16,711		5,380
Caustic soda	2,727		2,679
NaHS	8,588		5,845
Other	11		53
Total	$	99,390	$	85,330

Inventories are valued at the lower of cost or market. The market value of inventories was below recorded costs by approximately $1.8 million at September 30, 2014; therefore we reduced the value of inventory in our Unaudited Condensed Consolidated Financial Statements for this difference. At December 31, 2013, market values of our inventories exceeded recorded costs.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	September 30, 2014			December 31, 2013
Pipelines and related assets	$	460,118		$	338,920
Machinery and equipment	268,172			173,092
Transportation equipment	18,369			19,140
Marine vessels	594,322			554,679
Land, buildings and improvements	31,776			30,170
Office equipment, furniture and fixtures	5,541			5,633
Construction in progress	255,497			183,037
Other	34,336			23,303
Fixed assets, at cost	1,668,131			1,327,974
Less: Accumulated depreciation	(248,145		)	(199,230		)
Net fixed assets	$	1,419,986		$	1,128,744

Our depreciation expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Depreciation expense	$	20,736	$	11,362	$	52,422	$	32,920

6. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At September 30, 2014 and December 31, 2013, the unamortized excess cost amounts totaled $218.0 million and $225.7 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Genesis’ share of operating earnings	$	17,600		$	9,641		$	35,506		$	24,512
Amortization of excess purchase price	(2,583		)	(2,582		)	(7,749		)	(7,894		)
Net equity in earnings	$	15,017		$	7,059		$	27,757		$	16,618
Distributions received	$	21,758		$	11,610		$	49,383		$	32,624

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	September 30, 2014		December 31, 2013
BALANCE SHEET DATA:
Assets
Current assets	$	45,840	$	70,921
Fixed assets, net	1,023,865		1,028,808
Other assets	5,507		6,823
Total assets	$	1,075,212	$	1,106,552
Liabilities and equity
Current liabilities	$	20,624	$	55,918
Other liabilities	203,104		190,578
Equity	851,484		860,056
Total liabilities and equity	$	1,075,212	$	1,106,552



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
INCOME STATEMENT DATA:
Revenues	$	74,801	$	49,239	$	171,065	$	135,507
Operating income	$	46,096	$	28,419	$	99,199	$	75,946
Net income	$	44,881	$	27,725	$	96,402	$	73,928

7. Intangible Assets

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



	September 30, 2014						December 31, 2013
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	80,481	$	14,173	$	94,654	$	76,283	$	18,371
Licensing agreements	38,678		28,251		10,427		38,678		26,055		12,623
Segment total	133,332		108,732		24,600		133,332		102,338		30,994
Supply & Logistics:
Customer relationships	35,430		29,813		5,617		35,430		28,568		6,862
Intangibles associated with lease	13,260		3,394		9,866		13,260		3,039		10,221
Segment total	48,690		33,207		15,483		48,690		31,607		17,083
Other	22,314		7,951		14,363		21,356		6,505		14,851
Total	$	204,336	$	149,890	$	54,446	$	203,378	$	140,450	$	62,928

Our amortization expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Amortization expense	$	3,148	$	3,656	$	9,440	$	10,892

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



Remainder of	2014	$	3,180
	2015	$	10,874
	2016	$	9,412
	2017	$	8,249
	2018	$	7,328

8. Debt

Our obligations under debt arrangements consisted of the following:



	September 30, 2014		December 31, 2013
Senior secured credit facility	$	335,000	$	582,800
7.875% senior unsecured notes (including unamortized premium of $673 and $772 in 2014 and 2013, respectively)	350,673		350,772
5.750% senior unsecured notes	350,000		350,000
5.625% senior unsecured notes	350,000		—
Total long-term debt	$	1,385,673	$	1,283,572

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

Senior Secured Credit Facility

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

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

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

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

At September 30, 2014, we had $335.0 million borrowed under our $1 billion credit facility, with $71.8 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 $13.2 million was outstanding at September 30, 2014. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our credit facility at September 30, 2014 was $651.8 million.

Senior Unsecured Notes

In November 2010, we issued $250 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2018 (the "2018 Notes"). The 2018 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year. In February 2012, we issued an additional $100 million of aggregate principal amount of the 2018 Notes. The additional 2018 Notes were issued at 101% of face value at an effective interest rate of 7.682%. The additional 2018 Notes have the same terms and conditions as the notes previously issued under their indenture. The issuance increased the total aggregate principal amount of the 2018 Notes under their indenture to $350 million.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

The 2018, 2021 and 2024 Notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and are each fully and unconditionally guaranteed, jointly and severally, by certain of our wholly-owned subsidiaries. We have the right to redeem the 2018 Notes at any time after December 15, 2014, at a premium to the face amount of the notes that varies based on the time remaining to maturity of the 2018 Notes. We have the right to redeem the 2021 Notes at any time after February 15, 2017, at a premium to the face amount of the 2021 Notes that varies based on the time remaining to maturity on the 2021 Notes. Prior to February 15, 2016, we may also redeem up to 35% of the principal amount of the 2021 Notes for 105.75% of the face amount with the proceeds from an equity offering of our common units. We have the right to redeem the 2024 Notes at any time after June 15, 2019, at a premium to the face amount of the 2024 Notes that varies based on the time remaining to maturity on the 2024 Notes. Prior to June 15, 2017, we may also redeem up to 35% of the principal amount of the 2024 Notes for 105.625% of the face amount with the proceeds from an equity offering of our common units.

9. Partners’ Capital and Distributions

On September 26, 2014, we issued 4,600,000 Class A common units in a public offering at a price of $50.71 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $225.6 million from that offering. We used the net proceeds for general partnership purposes, including the repayment of outstanding borrowings under our revolving credit facility. At September 30, 2014, our outstanding common units consisted of 93,250,988 Class A units and 39,997 Class B units.

Waiver Units

Our waiver units are non-voting securities entitled to a minimal preferential quarterly distribution. At issuance, our waiver units were comprised of four classes (designated Class 1, Class 2, Class 3 and Class 4) of 1,738,000 units each. The waiver units in each class were/are convertible into Class A common units at a 1:1 conversion rate in the calendar quarter during which each of our common units receives a specified minimum quarterly distribution and our distribution coverage ratio (after giving effect to the then convertible waiver units) would be at least 1.1 times. The minimum distribution per common unit required for conversion is $0.52 for our Class 4 waiver units.

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

Our Class 4 waiver units will become convertible into Class A common units on November 14, 2014, as we will satisfy the distribution conversion coverage ratio requirement and will pay a minimum distribution of $0.52 per common unit.

Distributions

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



Distribution For	Date Paid		Per Unit Amount		Total Amount
2013
1^st Quarter	May 15, 2013		$	0.4975	$	40,405
2^nd Quarter	August 14, 2013		$	0.5100	$	42,302
3^rd Quarter	November 14, 2013		$	0.5225	$	46,344
4^th Quarter	February 14, 2014		$	0.5350	$	47,453
2014
1^st Quarter	May 15, 2014		$	0.5500	$	48,783
2^nd Quarter	August 14, 2014		$	0.5650	$	50,114
3^rdQuarter	November 14, 2014	⁽¹⁾	$	0.5800	$	54,112

(1) This distribution will be paid to unitholders of record as of October 31, 2014.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. Business Segment Information

Our operations consist of three operating segments:


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


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


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

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

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases.

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

Segment information for the periods presented below was as follows:



	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended September 30, 2014
Segment margin (a)	$	37,020	$	21,855		$	35,915		$	94,790
Capital expenditures (b)	$	35,289	$	1,254		$	103,334		$	139,877
Revenues:
External customers	$	16,689	$	53,930		$	893,495		$	964,114
Intersegment (c)	4,634		(2,722		)	(1,912		)	—
Total revenues of reportable segments	$	21,323	$	51,208		$	891,583		$	964,114
Three Months Ended September 30, 2013
Segment margin (a)	$	29,860	$	19,163		$	15,801		$	64,824
Capital expenditures (b)	$	38,514	$	632		$	290,942		$	330,088
Revenues:
External customers	$	16,636	$	55,025		$	1,018,632		$	1,090,293
Intersegment (c)	6,581		(2,615		)	(3,966		)	—
Total revenues of reportable segments	$	23,217	$	52,410		$	1,014,666		$	1,090,293
Nine Months Ended September 30, 2014
Segment Margin (a)	$	93,078	$	64,354		$	97,390		$	254,822
Capital expenditures (b)	$	76,606	$	2,153		$	304,020		$	382,779
Revenues:
External customers	$	52,897	$	166,589		$	2,779,396		$	2,998,882
Intersegment (c)	12,538		(8,387		)	(4,151		)	—
Total revenues of reportable segments	$	65,435	$	158,202		$	2,775,245		$	2,998,882
Nine Months Ended September 30, 2013
Segment Margin (a)	$	81,512	$	55,824		$	69,995		$	207,331
Capital expenditures (b)	$	159,922	$	2,296		$	347,001		$	509,219
Revenues:
External customers	$	53,121	$	161,492		$	2,959,182		$	3,173,795
Intersegment (c)	13,412		(8,122		)	(5,290		)	—
Total revenues of reportable segments	$	66,533	$	153,370		$	2,953,892		$	3,173,795

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Total assets by reportable segment were as follows:



	September 30, 2014		December 31, 2013
Pipeline transportation	$	1,114,347	$	1,075,235
Refinery services	407,618		417,121
Supply and logistics	1,520,281		1,312,461
Other assets	70,366		57,385
Total consolidated assets	$	3,112,612	$	2,862,202


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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Margin	$	94,790		$	64,824		$	254,822		$	207,331
Corporate general and administrative expenses	(12,865		)	(11,113		)	(37,715		)	(32,255		)
Depreciation and amortization	(25,148		)	(16,066		)	(64,919		)	(46,780		)
Interest expense	(20,441		)	(12,587		)	(47,314		)	(36,283		)
Distributable cash from equity investees in excess of equity in earnings	(6,741		)	(5,204		)	(20,326		)	(16,659		)
Non-cash items not included in Segment Margin	1,653			507			1,935			(2,828		)
Cash payments from direct financing leases in excess of earnings	(1,404		)	(1,291		)	(4,113		)	(3,786		)
Income tax expense	(731		)	(596		)	(2,334		)	(510		)
Discontinued operations	—			(508		)	—			(949		)
Income from continuing operations	$	29,113		$	17,966		$	80,036		$	67,281

(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 $23.4 million and $36.1 million during the three and nine months ended September 30, 2014 and $5.2 million and $71.4 million during the three and nine months ended September 30, 2013 representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline.


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

11. Transactions with Related Parties

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	867	$	863	$	2,235	$	2,344
Petroleum products sales to Davison family businesses⁽²⁾	—		399		—		1,043
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	150	$	150	$	450	$	450


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


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

Amount due from Related Party

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. Supplemental Cash Flow Information

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



	Nine Months Ended September 30,
	2014			2013
(Increase) decrease in:
Accounts receivable	$	43,591		$	(92,906	)
Inventories	(14,060		)	(32,073		)
Other current assets	48,582			13,897
Increase (decrease) in:
Accounts payable	(8,576		)	75,506
Accrued liabilities	(30,487		)	7,222
Net changes in components of operating assets and liabilities	$	39,050		$	(28,354	)

Payments of interest and commitment fees were $46.3 million and $32.5 million for the nine months ended September 30, 2014 and September 30, 2013, respectively.

At September 30, 2014 and September 30, 2013, we had incurred liabilities for fixed and intangible asset additions totaling $61.2 million and $22.9 million, respectively, that had not been paid at the end of the third 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 September 30, 2014 we had incurred liabilities for other asset additions totaling $9.8 million, that had not been paid at the end of the third quarter and, therefore, were not included in the caption "Other, net" under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

13. Derivatives

Commodity Derivatives

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2014, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. We had no outstanding derivative contracts that were designated as hedges under accounting rules.



	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	601		406
Weighted average contract price per bbl	$	95.06	$	93.67
Diesel futures:
Contract volumes (1,000 bbls)	100		—
Weighted average contract price per gal	$	2.78	$	—
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	435		50
Weighted average contract price per bbl	$	84.22	$	83.85
Crude oil options:
Contract volumes (1,000 bbls)	90		—
Weighted average premium received	$	1.19	$	—
Diesel options:
Contract volumes (1,000 bbls)	20		—
Weighted average premium received	$	2.08	$	—

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.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at September 30, 2014 and December 31, 2013:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	September 30, 2014			December 31, 2013
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	2,922		$	615
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(1,155		)	(615		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	1,767		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,155	)	$	(4,527	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,155			4,527
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—

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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of September 30, 2014, we had a net broker receivable of approximately $3.7 million (consisting of initial margin of $1.9 million increased by $1.8 million of variation margin). As of December 31, 2013, we had a net broker receivable of approximately $5.3 million (consisting of initial margin of $4.1 million increased by $1.2 million of variation margin). At September 30, 2014 and December 31, 2013, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
Commodity derivatives - futures and call options:
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	$	(8,738	)	$	(4,522	)	$	(5,242	)	$	(2,877	)
Total commodity derivatives		$	(8,738	)	$	(4,522	)	$	(5,242	)	$	(2,877	)

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Fair-Value Measurements

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


(1)	Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;


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


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

As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013.



	Fair Value at							Fair Value at
	September 30, 2014							December 31, 2013
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	2,922		$	—	$	—	$	615		$	—	$	—
Liabilities	$	(1,155	)	$	—	$	—	$	(4,527	)	$	—	$	—

Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.

See Note 13 for additional information on our derivative instruments.

Other Fair Value Measurements

We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates for similar instruments with comparable maturities. At September 30, 2014, our senior unsecured notes had a carrying value of $1.1 billion and a fair value of $1.1 billion, compared to $0.7 billion and $0.7 billion, respectively, at December 31, 2013. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.

15. Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however, no assurance can be made that such environmental releases may not substantially affect our business.

We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations, or cash flows.

16. Subsequent Events

On October 10, 2014, we entered into definitive agreements to acquire from Mid Ocean Tanker Company, LLC, the M/T American Phoenix and two related charters for approximately $157 million. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity, which was completed in 2012. It is under charter to large energy companies into 2020.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

17. Condensed Consolidating Financial Information

Our $1.05 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 8 for additional information regarding our consolidated debt obligations.

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

September 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	9	$	—	$	16,240		$	676		$	—		$	16,925
Other current assets	1,189,487		—		429,295			55,263			(1,221,663		)	452,382
Total current assets	1,189,496		—		445,535			55,939			(1,221,663		)	469,307
Fixed assets, at cost	—		—		1,545,752			122,379			—			1,668,131
Less: Accumulated depreciation	—		—		(226,936		)	(21,209		)	—			(248,145		)
Net fixed assets	—		—		1,318,816			101,170			—			1,419,986
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	29,585		—		236,933			148,196			(155,488		)	259,226
Equity investees	—		—		639,047			—			—			639,047
Investments in subsidiaries	1,442,767		—		127,585			—			(1,570,352		)	—
Total assets	$	2,661,848	$	—	$	3,092,962		$	305,305		$	(2,947,503	)	$	3,112,612
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	19,142	$	—	$	1,616,529		$	19,477		$	(1,221,251	)	$	433,897
Senior secured credit facility	335,000		—		—			—			—			335,000
Senior unsecured notes	1,050,673		—		—			—			—			1,050,673
Deferred tax liabilities	—		—		17,178			—			—			17,178
Other liabilities	—		—		15,277			158,870			(155,316		)	18,831
Total liabilities	1,404,815		—		1,648,984			178,347			(1,376,567		)	1,855,579
Partners’ capital	1,257,033		—		1,443,978			126,958			(1,570,936		)	1,257,033
Total liabilities and partners’ capital	$	2,661,848	$	—	$	3,092,962		$	305,305		$	(2,947,503	)	$	3,112,612

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2013



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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	887,709		$	22,104		$	(18,230	)	$	891,583
Refinery services	—			—		52,046			2,193			(3,031		)	51,208
Pipeline transportation services	—			—		15,313			6,010			—			21,323
Total revenues	—			—		955,068			30,307			(21,261		)	964,114
COSTS AND EXPENSES:
Supply and logistics costs	—			—		849,337			22,601			(18,229		)	853,709
Refinery services operating costs	—			—		29,332			2,167			(2,468		)	29,031
Pipeline transportation operating costs	—			—		6,820			373			—			7,193
General and administrative	—			—		13,735			30			—			13,765
Depreciation and amortization	—			—		23,841			1,307			—			25,148
Total costs and expenses	—			—		923,065			26,478			(20,697		)	928,846
OPERATING INCOME	—			—		32,003			3,829			(564		)	35,268
Equity in earnings of subsidiaries	49,550			—		223			—			(49,773		)	—
Equity in earnings of equity investees	—			—		15,017			—			—			15,017
Interest (expense) income, net	(20,437		)	—		3,900			(3,904		)	—			(20,441		)
Income from continuing operations before income taxes	29,113			—		51,143			(75		)	(50,337		)	29,844
Income tax expense	—			—		(985		)	254			—			(731		)
Income from continuing operations	29,113			—		50,158			179			(50,337		)	29,113
Income from discontinued operations	—			—		—			—			—			—
NET INCOME	$	29,113		$	—	$	50,158		$	179		$	(50,337	)	$	29,113

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2013



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	1,013,036		$	38,908		$	(37,278	)	$	1,014,666
Refinery services	—			—		50,609			4,199			(2,398		)	52,410
Pipeline transportation services	—			—		16,604			6,613			—			23,217
Total revenues	—			—		1,080,249			49,720			(39,676		)	1,090,293
COSTS AND EXPENSES:
Supply and logistics costs	—			—		996,937			39,201			(37,278		)	998,860
Refinery services operating costs	—			—		31,840			3,862			(2,662		)	33,040
Pipeline transportation operating costs	—			—		6,075			203			—			6,278
General and administrative	—			—		11,927			32			—			11,959
Depreciation and amortization	—			—		14,789			1,277			—			16,066
Total costs and expenses	—			—		1,061,568			44,575			(39,940		)	1,066,203
OPERATING INCOME	—			—		18,681			5,145			264			24,090
Equity in earnings of subsidiaries	31,046			—		1,078			—			(32,124		)	—
Equity in earnings of equity investees	—			—		7,059			—			—			7,059
Interest (expense) income, net	(12,572		)	—		4,011			(4,026		)	—			(12,587		)
Income from continuing operations before income taxes	18,474			—		30,829			1,119			(31,860		)	18,562
Income tax expense	—			—		(505		)	(91		)	—			(596		)
Income from continuing operations	18,474			—		30,324			1,028			(31,860		)	17,966
Income from discontinued operations	—			—		508			—			—			508
NET INCOME	$	18,474		$	—	$	30,832		$	1,028		$	(31,860	)	$	18,474

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2014



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	2,766,077		$	84,866		$	(75,698	)	$	2,775,245
Refinery services	—			—		155,470			12,838			(10,106		)	158,202
Pipeline transportation services	—			—		46,604			18,831			—			65,435
Total revenues	—			—		2,968,151			116,535			(85,804		)	2,998,882
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,667,317			83,517			(75,697		)	2,675,137
Refinery services operating costs	—			—		91,322			12,225			(10,173		)	93,374
Pipeline transportation operating costs	—			—		21,778			1,276			—			23,054
General and administrative	—			—		40,381			90			—			40,471
Depreciation and amortization	—			—		61,017			3,902			—			64,919
Total costs and expenses	—			—		2,881,815			101,010			(85,870		)	2,896,955
OPERATING INCOME	—			—		86,336			15,525			66			101,927
Equity in earnings of subsidiaries	127,343			—		3,982			—			(131,325		)	—
Equity in earnings of equity investees	—			—		27,757			—			—			27,757
Interest (expense) income, net	(47,307		)	—		11,798			(11,805		)	—			(47,314		)
Income from continuing operations before income taxes	80,036			—		129,873			3,720			(131,259		)	82,370
Income tax expense	—			—		(2,462		)	128			—			(2,334		)
Income from continuing operations	80,036			—		127,411			3,848			(131,259		)	80,036
Income from discontinued operations	—			—		—			—			—			—
NET INCOME	$	80,036		$	—	$	127,411		$	3,848		$	(131,259	)	$	80,036

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2013



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	2,940,710		$	112,977		$	(99,795	)	$	2,953,892
Refinery services	—			—		150,058			13,558			(10,246		)	153,370
Pipeline transportation services	—			—		46,461			20,072			—			66,533
Total revenues	—			—		3,137,229			146,607			(110,041		)	3,173,795
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,879,118			106,713			(99,795		)	2,886,036
Refinery services operating costs	—			—		95,922			12,660			(10,278		)	98,304
Pipeline transportation operating costs	—			—		19,497			1,010			—			20,507
General and administrative	—			—		34,620			92			—			34,712
Depreciation and amortization	—			—		43,691			3,089			—			46,780
Total costs and expenses	—			—		3,072,848			123,564			(110,073		)	3,086,339
OPERATING INCOME	—			—		64,381			23,043			32			87,456
Equity in earnings of subsidiaries	104,431			—		10,849			—			(115,280		)	—
Equity in earnings of equity investees	—			—		16,618			—			—			16,618
Interest (expense) income, net	(36,209		)	—		12,087			(12,161		)	—			(36,283		)
Income from continuing operations before income taxes	68,222			—		103,935			10,882			(115,248		)	67,791
Income tax benefit (expense)	—			—		(335		)	(175		)	—			(510		)
Income from continuing operations	68,222			—		103,600			10,707			(115,248		)	67,281
Income from discontinued operations	—			—		941			—			—			941
NET INCOME	$	68,222		$	—	$	104,541		$	10,707		$	(115,248	)	$	68,222

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 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	$	17,760		$	—	$	288,988		$	10,706		$	(109,335	)	$	208,119
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(330,287		)	(5,774		)	—			(336,061		)
Cash distributions received from equity investees - return of investment	38,236			—		11,353			—			(38,237		)	11,352
Investments in equity investees	(225,610		)	—		(40,426		)	—			225,610			(40,426		)
Repayments on loan to non-guarantor subsidiary	—			—		3,697			—			(3,697		)	—
Proceeds from asset sales	—			—		178			—			—			178
Other, net	—			—		(4,690		)	(16		)	—			(4,706		)
Net cash provided by (used) in investing activities	(187,374		)	—		(360,175		)	(5,790		)	183,676			(369,663		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,420,900			—		—			—			—			1,420,900
Repayments on senior secured credit facility	(1,668,700		)	—		—			—			—			(1,668,700		)
Proceeds from issuance of senior unsecured notes	350,000			—		—			—			—			350,000
Debt issuance costs	(11,857		)	—		—			—			—			(11,857		)
Issuance of common units for cash, net	225,610			—		225,610			—			(225,610		)	225,610
Distributions to partners/owners	(146,350		)	—		(146,350		)	(1,253		)	147,603			(146,350		)
Other, net	—			—		106			(3,772		)	3,666			—
Net cash provided by (used in) financing activities	169,603			—		79,366			(5,025		)	(74,341		)	169,603
Net (decrease) increase in cash and cash equivalents	(11		)	—		8,179			(109		)	—			8,059
Cash and cash equivalents at beginning of period	20			—		8,061			785			—			8,866
Cash and cash equivalents at end of period	$	9		$	—	$	16,240		$	676		$	—		$	16,925

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2013



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash (used in) provided by operating activities	$	(139,747	)	$	—	$	348,447		$	20,540		$	(119,902	)	$	109,338
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(188,878		)	(10,756		)	—			(199,634		)
Cash distributions received from equity investees - return of investment	8,711			—		8,272			—			(8,711		)	8,272
Investments in equity investees	(263,597		)	—		(71,443		)	—			263,597			(71,443		)
Acquisitions	—			—		(230,921		)	—			—			(230,921		)
Repayments on loan to non-guarantor subsidiary	—			—		3,341			—			(3,341		)	—
Proceeds from asset sales	—			—		810			—			—			810
Other, net	—			—		(1,004		)	—			—			(1,004		)
Net cash used in investing activities	(254,886		)	—		(479,823		)	(10,756		)	251,545			(493,920		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,234,500			—		—			—			—			1,234,500
Repayments on senior secured credit facility	(1,323,200		)	—		—			—			—			(1,323,200		)
Proceeds from issuance of senior unsecured notes	350,000			—		—			—			—			350,000
Debt issuance costs	(8,157		)	—		—			—			—			(8,157		)
Issuance of common units for cash, net	263,597			—		263,597			—			(263,597		)	263,597
Distributions to partners/owners	(122,097		)	—		(122,097		)	(6,545		)	128,642			(122,097		)
Other, net	—			—		(5,476		)	(2,320		)	3,312			(4,484		)
Net cash provided by (used in) financing activities	394,643			—		136,024			(8,865		)	(131,643		)	390,159
Net (decrease) increase in cash and cash equivalents	10			—		4,648			919			—			5,577
Cash and cash equivalents at beginning of period	10			—		11,214			58			—			11,282
Cash and cash equivalents at end of period	$	20		$	—	$	15,862		$	977		$	—		$	16,859

Table of Contents

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

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K for the year ended December 31, 2013.

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


•	Overview


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income of $29.1 million, or $0.33 per common unit, during the three months ended September 30, 2014 (“2014 Quarter”) compared to net income of $18.5 million or $0.22 per common unit, during the three months ended September 30, 2013 (“2013 Quarter”).

Available Cash before Reserves increased $17.5 million, or 41%, in the 2014 Quarter (as compared to the 2013 Quarter) to $60.8 million. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin (as described below in “Financial Measures”) increased by $30.0 million, or 46%, in the 2014 Quarter, as compared to the 2013 Quarter.

The increase in our Segment Margin resulted primarily from increases attributable to our pipeline transportation, refinery services and supply and logistics segments of $7.2 million, $2.7 million and $20.1 million, respectively. These increases, as discussed in more detail below, are primarily related to assets recently acquired, including organic growth projects recently placed in-service. These increases 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.

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

Distribution Increase

In October 2014, we declared our thirty-seventh consecutive increase in our quarterly distribution to our common unitholders. Thirty-two of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In November 2014, we will pay a distribution of $0.58 per unit representing a 11.0% increase from our distribution of $0.5225 per unit related to the third quarter of 2013.

Financial Measures

Segment Margin

We define Segment Margin, which is a "non-GAAP" measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP, as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment.

A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 10 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

Table of Contents

Available Cash before Reserves

This Quarterly Report on Form 10-Q includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in GAAP. The accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure – income from continuing operations. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

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

Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies.

Available Cash before Reserves, including applicable pro forma presentations, is a performance measure used by our management to compare cash flows generated by us to the cash distribution paid to our common unitholders. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investments. Among other things, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

Available Cash before Reserves is income from continuing operations as adjusted for specific items, the most significant of which are the addition of certain non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, and the subtraction of maintenance capital utilized. Maintenance capital is capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Our quarterly maintenance capital utilized is intended to represent the amount of cash reserves we believe is prudent to establish each quarter attributable to maintenance capital requirements in connection with determining the amount of distributable or discretionary cash flow attributable to that quarter, which cash flow we refer to as Available Cash before Reserves. We believe the most useful quarterly maintenance capital utilized amount is that portion of the amount of previously incurred maintenance capital expenditures that we realize and/or utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components. Because we have not historically used maintenance capital utilized, our future maintenance capital utilized calculations will reflect the realization and/or utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

Table of Contents

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



	Three Months Ended September 30,
	2014			2013
	(in thousands)
Income from continuing operations	$	29,113		$	17,966
Depreciation and amortization	25,148			16,066
Cash received from direct financing leases not included in income	1,404			1,291
Cash effects of sales of certain assets	45			184
Effects of distributable cash generated by equity method investees not included in income	6,741			5,204
Cash effects of legacy stock appreciation rights plan	(129		)	(470		)
Non-cash legacy stock appreciation rights plan expense (credit)	(608		)	(181		)
Expenses related to acquiring or constructing growth capital assets	688			3,326
Unrealized loss (gain) on derivative transactions excluding fair value hedges	(3,460		)	(779		)
Maintenance capital utilized	(242		)	(610		)
Non-cash tax expense	381			350
Other items, net	1,717			922
Available Cash before Reserves	$	60,798		$	43,269

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2014 Quarter decreased $126.2 million, or 12%, from the 2013 Quarter. Additionally, our costs and expenses decreased $137.4 million, or 13%, 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 third quarter periods is attributable to a combination of decreased volumes from our continuing operations relating to our supply and logistics segment and a decrease in market prices for crude oil and petroleum products as described below.

Volumes from continuing operations decreased in our supply and logistics segment by 5% quarter to quarter and 4% between the nine month periods principally related to the transitioning of the operations of our refined products business in order to operate within current market conditions, partially offset by increased crude oil gathering and marketing activities. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") decreased 8% to $97.17 per barrel in the third quarter of 2014, as compared to $105.83 per barrel in the third quarter of 2013.

Segment Margin

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Pipeline transportation	$	37,020	$	29,860	$	93,078	$	81,512
Refinery services	21,855		19,163		64,354		55,824
Supply and logistics	35,915		15,801		97,390		69,995
Total Segment Margin	$	94,790	$	64,824	$	254,822	$	207,331

Table of Contents

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Margin	$	94,790		$	64,824		$	254,822		$	207,331
Corporate general and administrative expenses	(12,865		)	(11,113		)	(37,715		)	(32,255		)
Depreciation and amortization	(25,148		)	(16,066		)	(64,919		)	(46,780		)
Interest expense	(20,441		)	(12,587		)	(47,314		)	(36,283		)
Distributable cash from equity investees in excess of equity in earnings	(6,741		)	(5,204		)	(20,326		)	(16,659		)
Non-cash items not included in Segment Margin	1,653			507			1,935			(2,828		)
Cash payments from direct financing leases in excess of earnings	(1,404		)	(1,291		)	(4,113		)	(3,786		)
Income tax expense	(731		)	(596		)	(2,334		)	(510		)
Discontinued operations	—			(508		)	—			(949		)
Income from continuing operations	$	29,113		$	17,966		$	80,036		$	67,281

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

Table of Contents

Pipeline Transportation Segment

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Crude oil tariffs and revenues - onshore crude oil pipelines	$	10,754		$	10,667		$	31,642		$	30,071
Segment Margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees	21,696			11,776			46,534			31,489
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	6,014			6,703			18,888			20,457
Sales of onshore crude oil pipeline loss allowance volumes	2,378			3,650			7,233			9,292
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(5,433		)	(4,455		)	(16,080		)	(14,320		)
Payments received under direct financing leases not included in income	1,404			1,291			4,113			3,786
Other	207			228			748			737
Segment Margin	$	37,020		$	29,860		$	93,078		$	81,512

Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	61,907			52,557			57,175			53,629
Jay	22,759			39,808			24,965			35,365
Mississippi	14,460			17,768			14,918			18,561
Louisiana ⁽¹⁾	18,331			—			15,177			—
Onshore crude oil pipelines total	117,457			110,133			112,235			107,555

Offshore crude oil pipelines:
CHOPS⁽²⁾	186,470			160,105			182,371			133,868
Poseidon ⁽²⁾	213,855			203,909			208,696			209,713
Odyssey ⁽²⁾	51,314			45,073			45,626			44,254
GOPL	7,610			8,138			6,419			8,797
Offshore crude oil pipelines total	459,249			417,225			443,112			396,632

CO₂ pipeline (Mcf/day):
Free State	144,588			201,635			171,388			212,381

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

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

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

Pipeline transportation Segment Margin for the 2014 Quarter increased $7.2 million, or 24%. The significant components and details of this change were as follows:


•	Segment Margin from our offshore crude oil pipelines increased $9.9 million, primarily attributable to the SEKCO Pipeline, our 50/50 joint venture with Enterprise Products, being declared mechanically complete and earning certain minimum fees despite no crude oil throughput to date.

Table of Contents

•

Volumes on our onshore crude oil pipelines increased primarily due to the increased volumes on our Texas pipeline system and our Louisiana pipeline system. Our Louisiana pipeline system is a new 18-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm. This system was placed into service during the first quarter of 2014. These increases 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.

•

Although volumes on our Free State CO₂ pipeline system decreased 57,047 Mcf per day, or 28%, in the 2014 Quarter as compared to the 2013 Quarter, that decrease did not materially affect contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

Pipeline transportation Segment Margin for the nine month periods increased $11.6 million, or 14%. The significant components and details of this change were as follows:

•

Segment Margin from our offshore crude oil pipelines increased $15.0 million, primarily attributable to the SEKCO Pipeline, our 50/50 joint venture with Enterprise Products, being declared mechanically complete and earning certain minimum fees despite no crude throughput to date. In addition this increase in segment margin from offshore crude oil pipelines is also partially attributable to higher throughput volumes on our CHOPS pipeline in the current year.

•

Although volumes on our Free State CO₂ pipeline system decreased 40,993 Mcf per day, or 19%, in the first nine months of 2014 as compared to the first nine months of 2013, that decrease did not materially affect contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Table of Contents

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Volumes sold (in Dry short tons "DST"):
NaHS volumes	36,431			35,946			114,940			109,233
NaOH (caustic soda) volumes	23,368			24,492			71,467			65,442
Total	59,799			60,438			186,407			174,675

Revenues (in thousands):
NaHS revenues	$	39,409		$	38,493		$	123,679		$	117,790
NaOH (caustic soda) revenues	12,312			14,454			37,099			38,551
Other revenues	2,209			2,078			5,811			5,151
Total external segment revenues	$	53,930		$	55,025		$	166,589		$	161,492

Segment Margin (in thousands)	$	21,855		$	19,163		$	64,354		$	55,824

Average index price for NaOH per DST ⁽¹⁾	$	588		$	606		$	588		$	611
Raw material and processing costs as % of segment revenues	42		%	52		%	42		%	50		%

(1) Source: IHS Chemical

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

Refinery services Segment Margin for the 2014 Quarter increased $2.7 million, or 14%. The significant components and details of this change were as follows:

•

NaHS revenues increased 2.4% primarily due to a slight increase in volumes. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which these adjustments apply varies between periods, which had a slightly positive effect for the quarter.

•

Our raw material costs related to NaHS decreased correspondingly to the decrease in the average index price for caustic soda. We were able to realize benefits from operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition (including economies of scale) and utilization of caustic soda in our (and our customers') operations, and our logistics management capabilities.

•

Caustic soda revenues decreased 15% due to a reduction in our sales volumes, as well as a decrease in our sales price for caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda decreased to $588 per DST in the third quarter of 2014 compared to $606 per DST during the third quarter of 2013. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Table of Contents

Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

Refinery services Segment Margin for the nine month periods increased $8.5 million, or 15%. The significant components and details of this change were as follows:

•

NaHS revenues increased 5% due primarily to a slight increase in volumes. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which these adjustments apply varies between periods, which had a slightly positive effect for the nine months ending September 30, 2014.

•

Caustic soda revenues decreased 4% primarily due to a decrease in our sales price for caustic soda, which was partially offset by an increase in sales volumes. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda decreased to $588 per DST in the first nine months of 2014 compared to $611 per DST during the first nine months of 2013. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Supply and Logistics Segment

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Supply and logistics revenue	$	891,583		$	1,014,666		$	2,775,245		$	2,953,892
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(792,586		)	(949,049		)	(2,487,175		)	(2,743,628		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(62,534		)	(50,571		)	(189,833		)	(142,507		)
Segment Margin attributable to discontinued operations	—			514			—			1,076
Other	(548		)	241			(847		)	1,162
Segment Margin	$	35,915		$	15,801		$	97,390		$	69,995

Volumetric Data (average barrels per day):
Crude oil and petroleum products sales:
Continuing operations	96,521			101,635			97,626			101,452
Discontinued operations	—			14,642			—			13,018
Total crude oil and petroleum products sales	96,521			116,277			97,626			114,470

Table of Contents

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


•	utilizing our fleet of trucks and trailers, railcars, and barges to transport products (primarily crude oil and petroleum products) for customers, as well as for our own account to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;


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


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


•	purchasing petroleum products from refiners, transporting those products to one of our terminals, blending those 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.

Product purchase and sale activities account for a substantial majority of revenues and costs of our supply and logistics segment. For reference purposes, the average market prices of crude oil and petroleum products decreased 8% and increased 2% between the three and nine month periods, respectively, however that price volatility has a limited impact on our Segment Margin.

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

Segment Margin for our supply and logistics segment increased by $20.1 million, or 127% between the two third quarter periods.

In the 2014 Quarter, the increase in our Segment Margin was a result of contributions from our marine transportation business, including our offshore marine transportation business, which we acquired in August 2013. Additionally, Segment Margin increased as a result of increased crude oil marketing and gathering activities and improvement in our refined products business. These improvements included a reduction in volumes in our refined products business as we worked through the dislocations in the prices/margins for the underlying commodities. We continue to transition our refined products operations to a level and structure designed to operate within current market conditions in terms of costs, size and type of activity.

Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

Segment Margin for our supply and logistics segment increased by $27.4 million, or 39% between the two nine month periods.

The increase in our Segment Margin during the first nine months of 2014 was a result of contributions from our marine transportation business, including our offshore marine transportation business, which we acquired in August 2013. Additionally, Segment Margin increased as a result of increased crude oil marketing and gathering activities and improvement in our refined products business. These improvements included a reduction in volumes in our refined products business as we worked through the dislocations in the prices/margins for the underlying commodities. We continue to transition our refined products operations to a level and structure designed to operate within current market conditions in terms of costs, size and type of activity.

Table of Contents

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	10,909	$	6,141	$	29,806	$	20,977
Segment	896		845		2,718		2,351
Equity-based compensation plan expense	1,272		1,647		6,057		7,175
Third party costs related to business development activities and growth projects	688		3,326		1,890		4,209
Total general and administrative expenses	$	13,765	$	11,959	$	40,471	$	34,712

Total general and administrative expenses increased $1.8 million and $5.8 million between the three and nine month periods, respectively, primarily due to higher employee compensation expenses, partially offset by decreases in third party costs related to business development and growth activities. Decreases in equity-based compensation plan expense were primarily due to a decrease in the market prices of our common units. Market prices of our common units decreased 6% between September 30, 2014 as compared to June 30, 2014 and decreased 3% between September 30, 2013 and June 30, 2013.

Equity-based compensation plan expense decreased when comparing the nine months ended September 30, 2014 to the nine months ended September 30, 2013, as the market price of our common units changed minimally between September 30, 2014 and December 31, 2013 as compared to a 40% increase in the market price for our common units between September 30, 2013 and December 31, 2012. This was partially offset by an increase in the number of participants as of September 30, 2014 as compared to the number of participants as of September 30, 2013.

Depreciation and amortization expense



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Depreciation expense	$	20,736	$	11,362	$	52,422	$	32,920
Amortization of intangible assets	3,148		3,656		9,440		10,892
Amortization of CO2 volumetric production payments	1,264		1,048		3,057		2,968
Total depreciation and amortization expense	$	25,148	$	16,066	$	64,919	$	46,780

Total depreciation and amortization expense increased $9.1 million and $18.1 million, between the three and nine month periods, respectively, primarily as a result of the effect of newly acquired and constructed assets placed in service relative to the three and nine month periods in 2013. That increase in depreciation expense was partially offset by a decrease in the amortization of intangible assets. Depreciation expense increased $9.4 million and $19.5 million between the three and nine month periods, respectively, primarily as a result of the acquisition of our offshore marine transportation assets and recently completed growth projects. Amortization of intangible assets decreased $0.5 million and $1.5 million between the three and nine month periods, respectively, as we amortize our intangible assets over the period in which we expect them to contribute to our future cash flows.

Table of Contents

Interest expense, net



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	3,898		$	3,196		$	12,070		$	8,417
Interest expense, senior unsecured notes	16,844			11,922			43,203			33,697
Amortization of debt issuance costs and premium	1,221			1,106			3,541			3,234
Capitalized interest	(1,522		)	(3,637		)	(11,500		)	(9,065		)
Net interest expense	$	20,441		$	12,587		$	47,314		$	36,283

Net interest expense increased $7.9 million and $11.0 million between the three and nine month periods, respectively, primarily due to an increase in our average outstanding indebtedness from newly acquired and constructed assets. In February 2013, we issued an additional $350 million of aggregate principal amount of 5.75% senior unsecured notes to repay borrowings under our senior secured credit facility. Capitalized interest costs decreased $2.1 million over the three month periods primarily due to the completion of construction of the SEKCO pipeline, on which we had incurred capitalized interest cost prior to its completion in June 2014. Capitalized interest costs increased $2.4 million in the nine month period due to our growth capital expenditures when compared to the prior year period.

Income tax expense

A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

Other

Net income for the three months ended September 30, 2014 included an unrealized gain on derivative positions of $3.5 million. Net income for the same period in 2013 included an unrealized gain on derivative positions of $0.8 million. Net income for the nine months ended September 30, 2014 included an unrealized gain on derivative positions of $4.7 million. Net income for the same period in 2013 included an unrealized gain on derivative positions of $2.8 million. Those amounts are included in supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations and are not a component of Segment Margin.

Liquidity and Capital Resources

General

As of September 30, 2014, we had $651.8 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

Table of Contents

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.

In September 2014, we issued 4,600,000 Class A common units in a public offering at a price of $50.71 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $225.6 million from the offering. We used the net proceeds for general partnership purposes, including the repayment of borrowings under our revolving credit facility. See Note 9 to our Unaudited Condensed Consolidated Financial Statements for more information.

In June 2014, we amended and restated our $1 billion senior secured credit facility with a syndicate of banks to, among other things, extend the term of our credit facility to July 25, 2019. Additionally, we increased the accordion feature from $300 million to $500 million, giving us the ability to expand the size of the facility up to $1.5 billion for acquisitions or growth projects, subject to lender consent. The inventory financing sublimit tranche under our senior secured credit facility is $150 million, which is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. At any one time, we can have up to $100 million in letters of credit outstanding under our facility. We had $13.2 million in letters of credit outstanding at September 30, 2014. Due to the revolving nature of loans under our credit facility, we may make additional borrowings and periodic repayments and re-borrowings until the maturity date. At September 30, 2014, we had $335.0 million borrowed under our credit facility, with $71.8 million of the borrowed amount designated as a loan under the inventory sublimit. Thus, the total amount available for borrowings under our credit facility at September 30, 2014 was $651.8 million.

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


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

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

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

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

At September 30, 2014, long-term debt totaled $1.4 billion, consisting of $335.0 million outstanding under our credit facility (including $71.8 million borrowed under the inventory sublimit tranche), a $350.7 million carrying amount of senior unsecured notes due on December 15, 2018, a $350 million carrying amount of senior unsecured notes due on February 15, 2021 and a $350 million carrying amount of senior unsecured notes due on June 15, 2024.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facility and/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 amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem, as we make payments and receive payments for the purchase and sale of crude oil.

In our petroleum products activities, we buy products, and typically, either move those products to one of our storage facilities for further blending or sell those products within days of our purchase. The cash requirements for those activities can result in short term increases and decreases in our borrowings under our credit facility.

The storage of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the crude oil or petroleum products, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, we may be required to deposit margin funds with the NYMEX when prices increase as the

Table of Contents

value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.

See Note 12 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the nine months ended September 30, 2014 and September 30, 2013.

The increase in operating cash flow for the nine months ended September 30, 2014 compared to the same period in 2013 was primarily due to decreases in working capital needs and increases in cash earnings. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our working capital and, therefore, our operating cash flows between periods as the cost to acquire a barrel of oil or petroleum products will require more or less cash. Net cash flows provided by our operating activities for the nine months ended September 30, 2014 were $208.1 million compared to $109.3 million for the nine months ended September 30, 2013.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, growth projects and distributions to unitholders. We finance maintenance capital expenditures and smaller growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and growth projects) with borrowings under our credit facility, equity issuances and/or the issuance of senior unsecured notes.

Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, business and other asset acquisitions for the nine months ended September 30, 2014 and September 30, 2013 is as follows:



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets	$	4,731	$	334
Refinery services assets	1,709		546
Supply and logistics assets	4,124		2,186
Information technology systems	444		—
Total maintenance capital expenditures⁽¹⁾	11,008		3,066
Growth capital expenditures:
Pipeline transportation assets	35,799		88,145
Refinery services assets	444		1,750
Supply and logistics assets	299,896		113,894
Information technology systems	514		1,581
Total growth capital expenditures	336,653		205,370
Total capital expenditures for fixed and intangible assets	347,661		208,436
Capital expenditures for business combinations, net of liabilities assumed:
Acquisition of offshore marine transportation assets	—		230,921
Total business combinations capital expenditures	—		230,921
Capital expenditures related to equity investees ⁽²⁾	36,076		71,443
Total capital expenditures	$	383,737	$	510,800

(1) Maintenance capital expenditures were $6.7 million and $11.0 million, respectively, for the three and nine months ended September 30, 2014.

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

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

Table of Contents

Capital Expenditures for Acquisition

We have agreed to acquire for approximately $157 million the M/T American Phoenix and two related charters from Mid Ocean Tanker Company, LLC. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity, which was completed in 2012. It is under charter to large energy companies into 2020. This transaction is subject to receiving consents and approvals customary to these types of transactions, which we expect to receive in the near future.

Growth Capital Expenditures

Total capital expenditures on projects under construction during 2014 are estimated to be approximately $730 million in 2014 and in future periods. We anticipate that approximately $470 million of that total will be spent in 2014, inclusive of expenditures incurred through September 30, 2014. The most significant of these projects currently under construction are described below.

Gulf Coast Infrastructure

We have been improving existing assets and developing new infrastructure in Louisiana, including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal at Port Hudson, Louisiana, constructing a new 18-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at Scenic Station. The Port Hudson upgrades and new crude oil pipeline were completed in the first quarter of 2014, and Scenic Station became fully operational in July 2014.

Baton Rouge Terminal

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

Rail Projects

Walnut Hill - In the first quarter of 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank and related equipment and connections to our Jay System. This facility is capable of handling unit train shipments of oil for direct deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other markets in the Southeast at the option of the shippers. We completed construction of an additional tank at that site with 110,000 barrels of capacity, which allows us to handle increased rail and pipeline demand and became fully operational in April 2014.

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

Natchez - In the third quarter of 2013, we completed construction on a crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. That facility has the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada. During the first quarter of 2014, we completed construction on the second phase of that facility, which provides an additional 60 railcar spots and additional heated tanks.

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

Inland Marine Barge Transportation Expansion - We ordered 12 new-build barges and 10 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of 8 of these barges as of September 2014. We expect to take delivery of those remaining vessels periodically into 2016.

Table of Contents

SEKCO Pipeline

The SEKCO Pipeline, our 50/50 joint venture with Enterprise Products in the deepwater Gulf of Mexico, was declared mechanically complete in June and has been made available to serve the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. We have budgeted approximately $200 million for our cumulative share of the pipeline construction through 2014. In 2013 and 2012, we contributed $94.3 million and $63.7 million, respectively, to SEKCO that was used to fund our share of the construction costs incurred during those years. We have budgeted approximately $40.1 million in 2014, of which we have paid $36.1 million during the first nine months of the year.

Distributions to Unitholders

On November 14, 2014, we will pay a distribution of $0.5800 per common unit totaling $54.1 million with respect to the third quarter of 2014 to common unitholders of record on October 31, 2014. This is the thirty-seventh consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 9 to our Unaudited Condensed Consolidated Financial Statements.

Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Commercial Commitments

There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2013.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2013, nor do we have any debt or equity triggers based upon our unit or commodity prices.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:


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


•	throughput levels and rates;


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


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


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


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


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

Table of Contents


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


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


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


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


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


•	loss of key personnel;


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


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


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


•	our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flows;


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


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers or counterparties;


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


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


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

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 13 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this Quarterly Report on Form 10-Q is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

There were no changes during the period covered by this report that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, the Company continues to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

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, 2013. On September 22, 2014, 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, 2013 (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 factor 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. Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of the Annual Report.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. A publicly traded partnership can lose its status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is “qualifying income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest, dividends or similar sources, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years. Qualifying income does not include rental income from leasing personal property such as vessels.

The decision of the United States Court of Appeals for the Fifth Circuit in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. April 13, 2009) held that the marine time charter being analyzed in that case was a “lease” that generated rental income rather than income from transportation services for purposes of a foreign sales corporation provision of the Internal Revenue Code. Even though (i) the Tidewater case did not involve a publicly traded partnership and it was not decided under Section 7704 of the Internal Revenue Code relating to “qualifying income,” (ii) some experienced practitioners believe the decision was not well reasoned, (iii) the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with and will not acquiesce to the Fifth Circuit’s marine time charter analysis contained in the Tidewater case and (iv) the IRS has issued several favorable private letter rulings (which can be relied upon and cited as precedent by only the taxpayers that obtained them) relating to time charters since the Tidewater decision was issued, the Tidewater decision creates some uncertainty regarding the status of income from certain of our marine time charters as “qualifying income” under Section 7704 of the Internal Revenue Code. Notwithstanding the foregoing, the Tidewater case is relevant authority because it is the only case of which we and our outside tax counsel are aware directly analyzing whether a particular time charter would constitute a lease or service agreement for certain U.S. federal tax purposes. Due to the uncertainty created by the Tidewater decision, our outside tax counsel, Akin Gump Strauss Hauer & Feld, LLP, was required to change the standard in its opinion relating to our status as a partnership for federal income tax purposes to “should” from “will.”

Although we do not believe based upon our current operations that we are treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxable to them again as corporate distributions and no income, gains, losses, or deductions would flow through to them. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Table of Contents

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on us by any other state would reduce the cash available for distribution to our unitholders.

For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Table of Contents

Item 6. Exhibits.

(a) Exhibits



	3.1	Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Registration Statement on Form S-1, File No. 333-11545).
	3.2	Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to Form 10-Q for the quarterly period ended June 30, 2011, File No. 011-12295).
	3.3	Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.5	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.6	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007, File No. 001-12295).
	10.1	First Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 25, 2014 among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto incorporated by reference to Exhibit 1.1 to Form 8-K dated August 29, 2014, File number 1-12295.
*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Schema Document
*	101.CAL	XBRL Calculation Linkbase Document
*	101.LAB	XBRL Label Linkbase Document
*	101.PRE	XBRL Presentation Linkbase Document
*	101.DEF	XBRL Definition Linkbase Document



*	Filed herewith

Table of Contents

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:	October 31, 2014	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer