Genesis Energy L.P. - 10-Q quarterly report FY2012 Q3

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, 2012

¨ 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. Class A Common Units outstanding as of November 1, 2012 was 81,162,755.

Table of Contents

GENESIS ENERGY, L.P.

TABLE OF CONTENTS



		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Partners’ Capital	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
	1. Organization and Basis of Presentation and Consolidation	7
	2. Acquisitions	7
	3. Inventories	9
	4. Fixed Assets and Asset Retirement Obligations	9
	5. Equity Investees	10
	6. Intangible Assets	10
	7. Debt	11
	8. Partner's Capital and Distributions	12
	9. Business Segment Information	13
	10. Transactions with Related Parties	15
	11. Supplemental Cash Flow Information	16
	12. Derivatives	16
	13. Fair-Value Measurements	18
	14. Contingencies	19
	15. Income Taxes	19
	16. Condensed Consolidating Financial Information	19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	41
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
SIGNATURES		44

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, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,461		$	10,817
Accounts receivable - trade, net	318,892			237,989
Inventories	67,298			101,124
Other	25,616			26,174
Total current assets	427,267			376,104
FIXED ASSETS, at cost	684,663			541,138
Less: Accumulated depreciation	(148,712		)	(124,213		)
Net fixed assets	535,951			416,925
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	158,698			162,460
EQUITY INVESTEES	547,925			326,947
INTANGIBLE ASSETS, net of amortization	79,140			93,356
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	33,128			30,006
TOTAL ASSETS	$	2,107,155		$	1,730,844
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	254,688		$	199,357
Accrued liabilities	63,691			50,071
Total current liabilities	318,379			249,428
SENIOR SECURED CREDIT FACILITY	483,000			409,300
SENIOR UNSECURED NOTES	350,924			250,000
DEFERRED TAX LIABILITIES	11,598			12,549
OTHER LONG-TERM LIABILITIES	15,321			16,929
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS’ CAPITAL:
Common unitholders, 81,202,752 and 71,965,062 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively	927,933			792,638
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,107,155		$	1,730,844

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,
	2012			2011			2012			2011
REVENUES:
Supply and logistics	$	875,193		$	765,714		$	2,597,809		$	2,091,854
Refinery services	47,977			48,392			144,342			145,301
Pipeline transportation services	19,164			16,094			55,794			45,633
Total revenues	942,334			830,200			2,797,945			2,282,788
COSTS AND EXPENSES:
Supply and logistics product costs	811,896			710,355			2,412,404			1,961,038
Supply and logistics operating costs	40,953			33,478			119,576			83,516
Refinery services operating costs	29,243			30,136			91,072			89,986
Pipeline transportation operating costs	5,911			3,988			15,995			12,414
General and administrative	10,375			8,905			29,934			25,339
Depreciation and amortization	14,838			14,706			45,447			43,100
Total costs and expenses	913,216			801,568			2,714,428			2,215,393
OPERATING INCOME	29,118			28,632			83,517			67,395
Equity in earnings (losses) of equity investees	3,432			(412		)	7,971			3,377
Interest expense	(9,873		)	(8,960		)	(30,697		)	(26,670		)
Income before income taxes	22,677			19,260			60,791			44,102
Income tax benefit (expense)	8,517			(172		)	8,591			(626		)
NET INCOME	$	31,194		$	19,088		$	69,382		$	43,476
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.39		$	0.27		$	0.90		$	0.65
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	79,901			70,447			77,410			66,580

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
	2012	2011	2012			2011
Partners’ capital, January 1	71,965	64,615	$	792,638		$	669,264
Net income	—	—	69,382			43,476
Cash distributions	—	—	(104,008		)	(82,067		)
Issuance of common units for cash, net	5,750	7,350	169,421			184,969
Conversion of waiver units	3,476	—	—			—
Other	12	—	500			—
Partners' capital, September 30	81,203	71,965	$	927,933		$	815,642

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,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	69,382		$	43,476
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	45,447			43,100
Amortization of debt issuance costs and premium	2,655			2,102
Amortization of unearned income and initial direct costs on direct financing leases	(12,641		)	(12,968		)
Payments received under direct financing leases	16,389			16,389
Equity in earnings of investments in equity investees	(7,971		)	(3,377		)
Cash distributions of earnings of equity investees	16,151			6,725
Non-cash effect of equity-based compensation plans	4,617			(1,505		)
Deferred and other tax liabilities	(9,156		)	(27		)
Unrealized gains on derivative transactions	(1,251		)	(4,370		)
Other, net	438			339
Net changes in components of operating assets and liabilities (Note 11)	18,878			(50,738		)
Net cash provided by operating activities	142,938			39,146
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(116,702		)	(15,157		)
Cash distributions received from equity investees - return of investment	10,918			8,577
Investments in equity investees	(57,072		)	(194		)
Acquisitions	(205,576		)	(143,489		)
Proceeds from asset sales	667			4,444
Other, net	(1,012		)	129
Net cash used in investing activities	(368,777		)	(145,690		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,407,000			571,700
Repayments on senior secured credit facility	(1,333,300		)	(563,800		)
Proceeds from issuance of senior unsecured notes, including premium	101,000			—
Debt issuance costs	(7,109		)	(3,018		)
Issuance of common units for cash, net	169,421			184,969
Distributions to common unitholders	(104,008		)	(82,067		)
Other, net	(2,521		)	(2,626		)
Net cash provided by financing activities	230,483			105,158
Net increase (decrease) in cash and cash equivalents	4,644			(1,386		)
Cash and cash equivalents at beginning of period	10,817			5,762
Cash and cash equivalents at end of period	$	15,461		$	4,376

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 limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, 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, 2011.

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. Acquisitions

Interests in Gulf of Mexico Crude Oil Pipeline Systems

On January 3, 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility. We account for our interests in Poseidon and Odyssey under the equity method of accounting. We have recorded the assets acquired and liabilities assumed of GOPL in the Unaudited Condensed Consolidated Financial Statements at their estimated fair values on a preliminary basis. Management developed these preliminary fair values and we do not expect any material adjustments to these preliminary purchase price allocations as a result of the final valuation.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The preliminary allocation of the purchase price is summarized as follows:



Property and equipment	$	28,456
Equity investees	182,993
Asset retirement obligation assumed	(5,873		)
Total allocation	$	205,576

The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana.

Our Unaudited Condensed Consolidated Financial Statements include the results of the acquired pipeline interests since the effective closing date of the acquisition in January 2012. The following table presents selected financial information included in our Unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2012:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2012
Revenues	$	1,180	$	4,334
Equity in earnings of equity investees	$	3,497	$	9,194
Net income	$	3,950	$	11,128

The table below presents selected unaudited pro forma financial information for the three and nine months ended September 30, 2011 incorporating the historical results of the acquired pipeline interests. The pro forma financial information below has been prepared as if the acquisition had been completed at the beginning of the prior year and is based upon assumptions deemed appropriate by us and may not be indicative of actual results.



	Three Months Ended September 30,		Nine Months Ended September 30,
	2011
Pro forma earnings data:
Revenues	$	831,956	$	2,288,056
Equity in earnings of equity investees	$	2,605	$	11,963
Net income	$	20,903	$	48,941
Basic and diluted earnings per unit:
As reported net income per unit	$	0.27	$	0.65
Pro forma net income per unit	$	0.30	$	0.74
As reported units outstanding	70,447		66,580
Pro forma units outstanding	70,447		66,580

FMT Black Oil Barge Transportation Business

In August 2011, we completed the acquisition of the black oil barge transportation business of Florida Marine Transporters, Inc. and its affiliates (“FMT”). The purchase price was $143.5 million (including $2.5 million for fuel inventory and other costs). The acquired business was comprised of 30 barges (seven of which were initially sub-leased under terms similar to those of an existing FMT lease, which we subsequently purchased in February 2012 for $30.6 million) and 14 push/tow boats which transport heavy refined products, primarily serving refineries and storage terminals along the Gulf Coast,

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. The August 2011 acquisition and related transaction costs were funded with a portion of the net proceeds from the July 2011 public offering of our common units, whereby we raised approximately $185 million in net proceeds of equity capital. The February 2012 vessels purchase was funded with cash available under our credit facility.

The financial results of the acquired business are included in our supply and logistics segment from the date of the acquisition.

3. Inventories

The major components of inventories were as follows:



	September 30, 2012		December 31, 2011
Petroleum products	$	41,076	$	70,769
Crude oil	12,014		11,701
Caustic soda	6,829		11,312
NaHS	7,376		7,337
Other	3		5
Total	$	67,298	$	101,124

Inventories are valued at the lower of cost or market. At September 30, 2012 and December 31, 2011, market values of our inventories exceeded recorded costs.

4. Fixed Assets and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following:



	September 30, 2012			December 31, 2011
Pipelines and related assets	$	218,155		$	167,865
Machinery and equipment	63,091			46,233
Transportation equipment	20,280			21,732
Marine vessels	297,416			262,216
Land, buildings and improvements	14,037			13,140
Office equipment, furniture and fixtures	4,487			3,778
Construction in progress	53,135			14,236
Other	14,062			11,938
Fixed assets, at cost	684,663			541,138
Less: Accumulated depreciation	(148,712		)	(124,213		)
Net fixed assets	$	535,951		$	416,925

Our depreciation expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Depreciation expense	$	9,202	$	5,960	$	27,246	$	17,838

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

A reconciliation of our liability for asset retirement obligations is as follows:



December 31, 2011	$	5,900
Liabilities incurred and assumed in the current period	5,995
Accretion expense	600
September 30, 2012	$	12,495

We assumed asset retirement obligations of $5.9 million related to pipelines in connection with our acquisition of GOPL. See Note 2 for information related to our acquisitions.

5. 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, 2012 and December 31, 2011, the unamortized excess cost amounts totaled $236.6 million and $97.8 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,
	2012			2011			2012			2011
Genesis’ share of operating earnings	$	5,978		$	729		$	15,611		$	6,800
Amortization of excess purchase price	(2,546		)	(1,141		)	(7,640		)	(3,423		)
Net equity in earnings (losses)	$	3,432		$	(412	)	$	7,971		$	3,377
Distributions received	$	9,045		$	3,289		$	27,069		$	15,302

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



	September 30, 2012		December 31, 2011
Balance Sheet Information:
Assets
Current assets	$	65,250	$	12,732
Fixed assets, net	760,788		441,894
Other assets	10,964		18,000
Total assets	$	837,002	$	472,626
Liabilities and equity
Current liabilities	$	53,667	$	5,891
Other liabilities	118,226		8,536
Equity	665,109		458,199
Total liabilities and equity	$	837,002	$	472,626



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Income Statement Information:
Revenues	$	39,799	$	7,975	$	113,769	$	32,819
Operating income	$	19,810	$	576	$	53,597	$	11,768
Net income	$	19,196	$	576	$	51,553	$	11,778

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. Intangible Assets

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



	September 30, 2012						December 31, 2011
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	67,403	$	27,251	$	94,654	$	62,111	$	32,543
Licensing agreements	38,678		22,038		16,640		38,678		19,476		19,202
Supplier relationships	36,469		35,878		591		36,469		34,105		2,364
Segment total	169,801		125,319		44,482		169,801		115,692		54,109
Supply & Logistics:
Customer relationships	35,430		25,698		9,732		35,430		23,584		11,846
Intangibles associated with lease	13,260		2,447		10,813		13,260		2,092		11,168
Trade names	18,888		18,888		—		18,888		17,048		1,840
Segment total	67,578		47,033		20,545		67,578		42,724		24,854
Other	18,467		4,354		14,113		17,292		2,899		14,393
Total	$	255,846	$	176,706	$	79,140	$	254,671	$	161,315	$	93,356

Our amortization expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Amortization expense	$	4,520	$	7,721	$	15,390	$	22,367

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



Remainder of	2012	$	4,520
	2013	$	14,597
	2014	$	12,297
	2015	$	10,489
	2016	$	9,028

7. Debt

Our obligations under debt arrangements consisted of the following:



	September 30, 2012		December 31, 2011
Senior secured credit facility	$	483,000	$	409,300
7.875% senior unsecured notes (including unamortized premium of $924 and $0 in 2012 and 2011, respectively)	350,924		250,000
Total long-term debt	$	833,924	$	659,300

As of September 30, 2012, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indenture.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Senior Secured Credit Facility

In July 2012, we amended and restated our senior secured credit facility with a syndicate of banks to, among other things, increase the committed amount from $775 million to $1 billion and the accordion feature from $225 million to $300 million, giving us the ability to expand the size of the facility up to an aggregate $1.3 billion for acquisitions or internal growth projects, subject to lender consent. The inventory financing sublimit tranche was increased from $125 million to $150 million, and the term of our credit facility was extended to July 25, 2017.

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 1.75% to 2.75% on eurodollar borrowings and from 0.75% to 1.75% on alternate base rate borrowings.

•Letter of credit fees range from 1.75% to 2.75%.


•	The commitment fee on the unused committed amount will range from 0.375% to 0.50%.

At September 30, 2012, we had $483 million borrowed under our credit facility, with $48.6 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 $12.6 million was outstanding at September 30, 2012. 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, 2012 was $504.4 million.

Senior Unsecured Notes Issuance

On February 1, 2012, we issued an additional $100 million of aggregate principal amount of senior unsecured notes under our existing 7.875% senior unsecured notes due 2018 indenture. The notes were issued at 101% of face value at an effective interest rate of 7.682%. The notes have the same terms and conditions as the notes previously issued under the indenture. The issuance increased the total aggregate principal amount under the indenture to $350 million. The net proceeds were used to repay borrowings under our credit facility.

8. Partners’ Capital and Distributions

On March 28, 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. At September 30, 2012, our outstanding common units consisted of 81,162,755 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. The waiver units in each class are convertible into Class A common units in the calendar quarter at a 1:1 conversion rate during which each of our common units receives a specified minimum quarterly distribution and our distribution coverage ratio (after giving effect to the then convertible waiver units) would be at least 1.1 times. The minimum distribution per common unit required for conversion is $0.43 (Class 1), $0.46 (Class 2), $0.49 (Class 3) and $0.52 (Class 4).

On February 14, 2012, our Class 1 waiver units became convertible as we paid a distribution of $0.44 per common unit and satisfied the conversion coverage ratio requirement. All Class 1 waiver units were converted into common units by March 31, 2012.

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

At September 30, 2012, we had 3,476,466 waiver units outstanding comprised of the last two classes.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Distributions

We paid or will pay the following distributions in 2011 and 2012:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2011
1^st Quarter	May 13, 2011		$	0.4075	$	26,343
2^nd Quarter	August 12, 2011		$	0.4150	$	29,878
3^rd Quarter	November 14, 2011		$	0.4275	$	30,777
4^th Quarter	February 14, 2012		$	0.4400	$	31,677
2012
1^st Quarter	May 15, 2012		$	0.4500	$	35,759
2^nd Quarter	August 14, 2012		$	0.4600	$	36,554
3^rd Quarter	November 14, 2012	⁽¹⁾	$	0.4725	$	38,368

(1) This distribution will be paid to unitholders of record as of November 1, 2012.

9. Business Segment Information

Our operations consist of three operating segments:


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


(2)	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;


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

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

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the periods presented below was as follows:



	Pipeline Transportation		Refinery Services			Supply & Logistics			Total
Three Months Ended September 30, 2012
Segment margin (a)	$	23,295	$	18,983		$	23,651		$	65,929
Capital expenditures (b)	$	21,764	$	1,025		$	14,410		$	37,199
Revenues:
External customers	$	16,190	$	50,378		$	875,766		$	942,334
Intersegment (c)	2,974		(2,401		)	(573		)	—
Total revenues of reportable segments	$	19,164	$	47,977		$	875,193		$	942,334
Three Months Ended September 30, 2011
Segment margin (a)	$	16,030	$	17,992		$	18,909		$	52,931
Capital expenditures (b)	$	1,582	$	852		$	146,999		$	149,433
Revenues:
External customers	$	12,658	$	50,982		$	766,560		$	830,200
Intersegment (c)	3,436		(2,590		)	(846		)	—
Total revenues of reportable segments	$	16,094	$	48,392		$	765,714		$	830,200
Nine Months Ended September 30, 2012
Segment margin (a)	$	69,427	$	53,510		$	66,075		$	189,012
Capital expenditures (b)	$	300,093	$	2,295		$	77,414		$	379,802
Revenues:
External customers	$	44,564	$	151,326		$	2,602,055		$	2,797,945
Intersegment (c)	11,230		(6,984		)	(4,246		)	—
Total revenues of reportable segments	$	55,794	$	144,342		$	2,597,809		$	2,797,945
Nine Months Ended September 30, 2011
Segment margin (a)	$	50,639	$	54,887		$	44,233		$	149,759
Capital expenditures (b)	$	3,264	$	1,321		$	149,126		$	153,711
Revenues:
External customers	$	37,302	$	151,899		$	2,093,587		$	2,282,788
Intersegment (c)	8,331		(6,598		)	(1,733		)	—
Total revenues of reportable segments	$	45,633	$	145,301		$	2,091,854		$	2,282,788

Total assets by reportable segment were as follows:



	September 30, 2012		December 31, 2011
Pipeline transportation	$	870,966	$	594,728
Refinery services	413,888		426,993
Supply and logistics	774,002		659,576
Other assets	48,299		49,547
Total consolidated assets	$	2,107,155	$	1,730,844

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Segment Margin	$	65,929		$	52,931		$	189,012		$	149,759
Corporate general and administrative expenses	(9,428		)	(8,194		)	(26,756		)	(23,267		)
Depreciation and amortization	(14,838		)	(14,706		)	(45,447		)	(43,100		)
Interest expense	(9,873		)	(8,960		)	(30,697		)	(26,670		)
Distributable cash from equity investees in excess of equity in earnings	(5,613		)	(3,701		)	(19,098		)	(11,925		)
Non-cash items not included in segment margin	(2,222		)	3,061			(2,475		)	2,729
Cash payments from direct financing leases in excess of earnings	(1,278		)	(1,171		)	(3,748		)	(3,424		)
Income before income taxes	$	22,677		$	19,260		$	60,791		$	44,102

(b)

Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of internal growth projects) as well as acquisitions of businesses and interests in equity investees. Capital spending in our pipeline transportation segment included $5.7 million and $57.1 million during the three and nine months ended September 30, 2012, respectively, representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline. For the nine months ended September 30, 2012, capital spending in our pipeline transportation segment also included $205.6 million for the acquisition of interests in several Gulf of Mexico pipelines. For the nine months ended September 30, 2012, capital spending in our supply and logistics segment also included $30.6 million for the purchase of barge assets.


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

10. 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,
	2012		2011		2012		2011
Revenues:
Petroleum products sales to an affiliate of the Quintana Group ⁽¹⁾	$	6,376	$	5,948	$	21,142	$	27,202
Sales of CO₂ to Sandhill Group, LLC ⁽²⁾	838		946		2,111		1,921
Petroleum products sales to Davison family businesses ⁽¹⁾	326		737		1,012		1,224
Costs and expenses:
Marine operating fuel and expenses provided by an affiliate of the Quintana Group ⁽¹⁾	1,980		902		6,181		2,722
Amounts paid to our CEO in connection with the use of his aircraft	150		166		450		166

(1)

The Quintana Group, a private equity fund based in Houston, Texas, owned 10% of our Class A common units and 74% of our Class B common units at September 30, 2012. The Davison family owned 15% of our Class A common units at September 30, 2012. The Quintana Group monetized all of its remaining investment in us on October 5, 2012. Substantially in connection with that transaction, certain members of the Davison family, collectively, increased their investment in us to 17.2% of our Class A common units and 76.9% of our Class B units. Soley for financial statement disclosure purposes, we will continue to treat the Davison family and their affiliates as related parties.


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

Amounts due to and from Related Parties

At September 30, 2012 and December 31, 2011, an affiliate of the Quintana Group owed us $1.2 million and $1.9 million, respectively, for petroleum product sales. We owed such affiliate $0.1 million at September 30, 2012 and December 31, 2011, respectively, for marine related costs. Sandhill Group, LLC owed us $0.3 million and $0.2 million at September 30, 2012 and December 31, 2011, respectively, for purchases of CO₂.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. 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,
	2012			2011
(Increase) decrease in:
Accounts receivable	$	(80,789	)	$	(52,355	)
Inventories	33,826			(34,757		)
Other current assets	1,846			1,515
Increase (decrease) in:
Accounts payable	57,851			16,953
Accrued liabilities	6,144			17,906
Net changes in components of operating assets and liabilities	$	18,878		$	(50,738	)

Payments of interest and commitment fees were $24.4 million and $20.3 million for the nine months ended September 30, 2012 and 2011, respectively.

At September 30, 2012 and 2011, we had incurred liabilities for fixed and intangible asset additions totaling $4.8 million and $1.3 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, 2012, we had incurred liabilities for other asset additions totaling $0.6 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.

12. 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.

In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Unaudited Condensed Consolidated Balance Sheets.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2012, we had the following outstanding derivative commodity futures and options 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)	59		25
Weighted average contract price per bbl	$	92.69	$	92.19
Crude oil LLS/WTI swap:
Contract volumes (1,000 bbls)	100		—
Weighted average contract price per bbl	$	18.63	$	—
Heating oil futures:
Contract volumes (1,000 bbls)	94		66
Weighted average contract price per gal	$	3.12	$	3.16
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	640		200
Weighted average contract price per bbl	$	97.59	$	98.05
Crude oil options:
Contract volumes (1,000 bbls)	360		105
Weighted average premium received	$	1.69	$	0.54
Heating oil options:
Contract volumes (1,000 bbls)	10		—
Weighted average premium received	$	0.08	$	—

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.

The following tables reflect the estimated fair value gain (loss) position of our derivatives at September 30, 2012 and December 31, 2011:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	September 30, 2012				December 31, 2011
Asset Derivatives:
Commodity derivatives - futures and call options:
Undesignated hedges	Current Assets - Other	$	178			$	306
Total asset derivatives		$	178			$	306
Liability Derivatives:
Commodity derivatives - futures and call options:
Undesignated hedges	Current Assets - Other	$	(1,440	)	⁽¹⁾	$	(2,820	)	⁽¹⁾
Total liability derivatives		$	(1,440	)		$	(2,820	)

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended September 30,					Nine Months Ended September 30,
		2012			2011		2012			2011
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	—		$	—	$	—		$	(173	)
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	(5,817		)	2,587		(2,959		)	(11,050		)
Total commodity derivatives		$	(5,817	)	$	2,587	$	(2,959	)	$	(11,223	)

13. 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;


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


(3)	Level 3 fair values are based on unobservable inputs in which little or no market data exists. As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis at the dates indicated.



	Fair Value at							Fair Value at
	September 30, 2012							December 31, 2011
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	178		$	—	$	—	$	306		$	—	$	—
Liabilities	$	(1,440	)	$	—	$	—	$	(2,820	)	$	—	$	—

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 12 for additional information on our derivative instruments.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such assets within our Unaudited Condensed Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2012, our senior unsecured notes had a carrying value of $351 million and a fair value of $371.4 million, compared to $250 million and $253.1 million, respectively, at December 31, 2011. 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.

14. 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 material 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, as well as examinations 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.

15. Income Taxes

In the third quarter of 2012, we reversed $8.2 million of uncertain tax positions and recognized an income tax benefit in the Unaudited Condensed Consolidated Statements of Operations as a result of tax audit settlements and the expiration of statutes of limitations. These uncertain tax positions were included in Other Long-Term Liabilities in our Unaudited Condensed Consolidated Balance Sheets.

16. Condensed Consolidating Financial Information

Our $350 million aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. Each subsidiary guarantor and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P. See Note 7 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, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	11	$	—	$	14,753		$	697		$	—		$	15,461
Other current assets	744,217		—		387,772			38,521			(758,704		)	411,806
Total current assets	744,228		—		402,525			39,218			(758,704		)	427,267
Fixed assets, at cost	—		—		583,751			100,912			—			684,663
Less: Accumulated depreciation	—		—		(136,459		)	(12,253		)	—			(148,712		)
Net fixed assets	—		—		447,292			88,659			—			535,951
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	19,152		—		257,694			158,875			(164,755		)	270,966
Equity investees	—		—		547,925			—			—			547,925
Investments in subsidiaries	1,007,650		—		100,005			—			(1,107,655		)	—
Total assets	$	1,771,030	$	—	$	2,080,487		$	286,752		$	(2,031,114	)	$	2,107,155
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	9,173	$	—	$	1,047,542		$	19,987		$	(758,323	)	$	318,379
Senior secured credit facility	483,000		—		—			—			—			483,000
Senior unsecured notes	350,924		—		—			—			—			350,924
Deferred tax liabilities	—		—		11,598			—			—			11,598
Other liabilities	—		—		12,850			167,041			(164,570		)	15,321
Total liabilities	843,097		—		1,071,990			187,028			(922,893		)	1,179,222
Partners’ capital	927,933		—		1,008,497			99,724			(1,108,221		)	927,933
Total liabilities and partners’ capital	$	1,771,030	$	—	$	2,080,487		$	286,752		$	(2,031,114	)	$	2,107,155

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011



	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	$	3	$	—	$	9,182		$	1,632		$	—		$	10,817
Other current assets	597,966		—		341,131			31,897			(605,707		)	365,287
Total current assets	597,969		—		350,313			33,529			(605,707		)	376,104
Fixed assets, at cost	—		—		444,262			96,876			—			541,138
Less: Accumulated depreciation	—		—		(114,655		)	(9,558		)	—			(124,213		)
Net fixed assets	—		—		329,607			87,318			—			416,925
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	14,773		—		276,450			162,373			(167,774		)	285,822
Equity investees	—		—		326,947			—			—			326,947
Investments in subsidiaries	841,725		—		96,303			—			(938,028		)	—
Total assets	$	1,454,467	$	—	$	1,704,666		$	283,220		$	(1,711,509	)	$	1,730,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,529	$	—	$	835,013		$	17,562		$	(605,676	)	$	249,428
Senior secured credit facility	409,300		—		—			—			—			409,300
Senior unsecured notes	250,000		—		—			—			—			250,000
Deferred tax liabilities	—		—		12,549			—			—			12,549
Other liabilities	—		—		14,673			169,842			(167,586		)	16,929
Total liabilities	661,829		—		862,235			187,404			(773,262		)	938,206
Partners’ capital	792,638		—		842,431			95,816			(938,247		)	792,638
Total liabilities and partners’ capital	$	1,454,467	$	—	$	1,704,666		$	283,220		$	(1,711,509	)	$	1,730,844

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, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	869,726	$	31,113		$	(25,646	)	$	875,193
Refinery services	—			—		48,809		4,367			(5,199		)	47,977
Pipeline transportation services	—			—		12,596		6,568			—			19,164
Total revenues	—			—		931,131		42,048			(30,845		)	942,334
COSTS AND EXPENSES:
Supply and logistics costs	—			—		852,009		26,488			(25,648		)	852,849
Refinery services operating costs	—			—		29,339		4,565			(4,661		)	29,243
Pipeline transportation operating costs	—			—		5,661		250			—			5,911
General and administrative	—			—		10,343		32			—			10,375
Depreciation and amortization	—			—		13,940		898			—			14,838
Total costs and expenses	—			—		911,292		32,233			(30,309		)	913,216
OPERATING INCOME	—			—		19,839		9,815			(536		)	29,118
Equity in earnings of subsidiaries	41,052			—		5,738		—			(46,790		)	—
Equity in earnings of equity investees	—			—		3,432		—			—			3,432
Interest (expense) income, net	(9,858		)	—		4,119		(4,134		)	—			(9,873		)
Income before income taxes	31,194			—		33,128		5,681			(47,326		)	22,677
Income tax benefit	—			—		8,509		8			—			8,517
NET INCOME	$	31,194		$	—	$	41,637	$	5,689		$	(47,326	)	$	31,194

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, 2011



	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	$	—		$	—	$	765,714		$	—		$	—		$	765,714
Refinery services	—			—		48,700			3,805			(4,113		)	48,392
Pipeline transportation services	—			—		9,388			6,706			—			16,094
Total revenues	—			—		823,802			10,511			(4,113		)	830,200
COSTS AND EXPENSES:
Supply and logistics costs	—			—		743,833			—			—			743,833
Refinery services operating costs	—			—		30,448			3,612			(3,924		)	30,136
Pipeline transportation operating costs	—			—		3,818			170			—			3,988
General and administrative	—			—		8,905			—			—			8,905
Depreciation and amortization	—			—		14,057			649			—			14,706
Total costs and expenses	—			—		801,061			4,431			(3,924		)	801,568
OPERATING INCOME	—			—		22,741			6,080			(189		)	28,632
Equity in losses of subsidiaries	28,032			—		1,945			—			(29,977		)	—
Equity in earnings of equity investees	—			—		(412		)	—			—			(412		)
Interest (expense) income, net	(8,944		)	—		4,226			(4,242		)	—			(8,960		)
Income before income taxes	19,088			—		28,500			1,838			(30,166		)	19,260
Income tax (expense) benefit	—			—		(233		)	61			—			(172		)
NET INCOME	$	19,088		$	—	$	28,267		$	1,899		$	(30,166	)	$	19,088

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, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Supply and logistics	$	—		$	—	$	2,579,102	$	95,451		$	(76,744	)	$	2,597,809
Refinery services	—			—		142,716		13,756			(12,130		)	144,342
Pipeline transportation services	—			—		36,381		19,413			—			55,794
Total revenues	—			—		2,758,199		128,620			(88,874		)	2,797,945
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,525,474		83,250			(76,744		)	2,531,980
Refinery services operating costs	—			—		89,155		13,701			(11,784		)	91,072
Pipeline transportation operating costs	—			—		15,351		644			—			15,995
General and administrative	—			—		29,842		92			—			29,934
Depreciation and amortization	—			—		42,759		2,688			—			45,447
Total costs and expenses	—			—		2,702,581		100,375			(88,528		)	2,714,428
OPERATING INCOME	—			—		55,618		28,245			(346		)	83,517
Equity in earnings of subsidiaries	100,011			—		15,869		—			(115,880		)	—
Equity in earnings of equity investees	—			—		7,971		—			—			7,971
Interest (expense) income, net	(30,629		)	—		12,414		(12,482		)	—			(30,697		)
Income before income taxes	69,382			—		91,872		15,763			(116,226		)	60,791
Income tax benefit (expense)	—			—		8,630		(39		)	—			8,591
NET INCOME	$	69,382		$	—	$	100,502	$	15,724		$	(116,226	)	$	69,382

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, 2011



	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	$	—		$	—	$	2,091,854		$	—		$	—		$	2,091,854
Refinery services	—			—		142,992			12,953			(10,644		)	145,301
Pipeline transportation services	—			—		26,292			19,341			—			45,633
Total revenues	—			—		2,261,138			32,294			(10,644		)	2,282,788
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,044,554			—			—			2,044,554
Refinery services operating costs	—			—		88,641			11,836			(10,491		)	89,986
Pipeline transportation operating costs	—			—		11,937			477			—			12,414
General and administrative	—			—		25,339			—			—			25,339
Depreciation and amortization	—			—		41,153			1,947			—			43,100
Total costs and expenses	—			—		2,211,624			14,260			(10,491		)	2,215,393
OPERATING INCOME	—			—		49,514			18,034			(153		)	67,395
Equity in earnings of subsidiaries	70,092			—		5,238			—			(75,330		)	—
Equity in earnings of equity investees	—			—		3,377			—			—			3,377
Interest (expense) income, net	(26,616		)	—		12,726			(12,780		)	—			(26,670		)
Income before income taxes	43,476			—		70,855			5,254			(75,483		)	44,102
Income tax expense	—			—		(467		)	(159		)	—			(626		)
NET INCOME	$	43,476		$	—	$	70,388		$	5,095		$	(75,483	)	$	43,476

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, 2012



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash (used in) provided by operating activities	$	(91,453	)	$	—	$	304,617		$	17,700		$	(87,926	)	$	142,938
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(112,665		)	(4,037		)	—			(116,702		)
Cash distributions received from equity investees - return of investment	27,878			—		10,918			—			(27,878		)	10,918
Investments in equity investees	(169,421		)	—		(57,072		)	—			169,421			(57,072		)
Acquisitions	—			—		(205,576		)	—			—			(205,576		)
Repayments on loan to non-guarantor subsidiary	—			—		3,019			—			(3,019		)	—
Proceeds from asset sales	—			—		667			—			—			667
Other, net	—			—		(1,012		)	—			—			(1,012		)
Net cash used in investing activities	(141,543		)	—		(361,721		)	(4,037		)	138,524			(368,777		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,407,000			—		—			—			—			1,407,000
Repayments on senior secured credit facility	(1,333,300		)	—		—			—			—			(1,333,300		)
Proceeds from issuance of senior unsecured notes, including premium	101,000			—		—			—			—			101,000
Debt issuance costs	(7,109		)	—		—			—			—			(7,109		)
Issuance of common units for cash, net	169,421			—		169,421			—			(169,421		)	169,421
Distributions to partners/owners	(104,008		)	—		(104,008		)	(11,819		)	115,827			(104,008		)
Other, net	—			—		(2,738		)	(2,779		)	2,996			(2,521		)
Net cash provided by (used in) financing activities	233,004			—		62,675			(14,598		)	(50,598		)	230,483
Net increase (decrease) in cash and cash equivalents	8			—		5,571			(935		)	—			4,644
Cash and cash equivalents at beginning of period	3			—		9,182			1,632			—			10,817
Cash and cash equivalents at end of period	$	11		$	—	$	14,753		$	697		$	—		$	15,461

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, 2011



	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	$	(4,881	)	$	—	$	41,160		$	2,844		$	23		$	39,146
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(15,060		)	(97		)	—			(15,157		)
Cash distributions received from equity investees - return of investment	82,067			—		8,577			—			(82,067		)	8,577
Investments in equity investees	(184,969		)	—		(194		)	—			184,969			(194		)
Acquisitions	—			—		(143,489		)	—			—			(143,489		)
Repayments on loan to non-guarantor subsidiary	—			—		2,729			—			(2,729		)	—
Proceeds from asset sales	—			—		4,444			—			—			4,444
Other, net	—			—		129			—			—			129
Net cash used in investing activities	(102,902		)	—		(142,864		)	(97		)	100,173			(145,690		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	571,700			—		—			—			—			571,700
Repayments on senior secured credit facility	(563,800		)	—		—			—			—			(563,800		)
Debt issuance costs	(3,018		)	—		—			—			—			(3,018		)
Distributions to partners/owners	(82,067		)	—		(82,067		)	—			82,067			(82,067		)
Issuance of common units for cash, net	184,969			—		184,969			—			(184,969		)	184,969
Other, net	—			—		(2,626		)	(2,706		)	2,706			(2,626		)
Net cash provided by (used in) financing activities	107,784			—		100,276			(2,706		)	(100,196		)	105,158
Net increase (decrease) in cash and cash equivalents	1			—		(1,428		)	41			—			(1,386		)
Cash and cash equivalents at beginning of period	1			—		5,082			679			—			5,762
Cash and cash equivalents at end of period	$	2		$	—	$	3,654		$	720		$	—		$	4,376

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.

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


•	Overview


•	Acquisition


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income of $31.2 million, or $0.39 per common unit during the three months ended September 30, 2012 (“2012 Quarter”) compared to net income of $19.1 million or $0.27 per common unit during the three months ended September 30, 2011 (“2011 Quarter”). The significant factors benefiting net income were improved operating results by all of our business segments and a decrease in our income tax expense. The increases in net income were partially offset by increases in general and administrative expenses and interest costs. A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.

Segment Margin (as described below in “Financial Measures”) increased by $13 million, or 25%, in the 2012 Quarter, as compared to the 2011 Quarter. This increase resulted from improvement in Segment Margin in our pipeline transportation, refinery services and supply and logistics segments of 45%, 6% and 25%, respectively. The contribution from our interests in certain Gulf of Mexico pipelines that we acquired in 2012 and higher crude oil tariff revenues were the primary factors increasing pipeline transportation segment margin. Results for our pipeline transportation segment were somewhat reduced during both quarters due to ongoing improvements at several dedicated fields. Improvements at those fields were substantially completed late in the 2012 Quarter. Our refinery services segment margin increased primarily as a result of increased NaHS sales volumes and operating efficiencies realized at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our, and our customers', operations. Our supply and logistics segment benefited from acquisitions and other growth initiatives completed in the second half of 2011 as well as higher volumes handled by our expanded trucking and barge fleets.

Available Cash before Reserves increased $8.8 million, or 24%, in the 2012 Quarter (as compared to the 2011 Quarter) to $45.9 million consistent with the increase in net income described above. See “Financial Measures” below for additional information on Available Cash before Reserves.

Distribution Increase

In October 2012, we declared our twenty-ninth consecutive increase in our quarterly distribution to our common unitholders relative to the third quarter of 2012. During that period, twenty-four of those quarterly increases have been 10% or greater year-over-year. In November 2012, we will pay a distribution of $0.4725 per unit representing a 10.5% increase from our distribution of $0.4275 per unit related to the third quarter of 2011. During the third quarter of 2012, we paid a distribution of $0.46 per unit related to the second quarter of 2012.

Acquisition

In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility.

This acquisition complements our existing infrastructure in the Gulf of Mexico and enhances our ability to provide capacity and market optionality to producers for their existing and future developments as well as our refining customers

Table of Contents

onshore Texas and Louisiana. The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of Enterprise Products serves as the operator of Poseidon. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco, ConocoPhillips and Shell. An affiliate of Shell serves as the operator of Eugene Island. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey, and an affiliate of Shell serves as the operator of Odyssey.

Financial Measures

In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that we use to manage the business and to review the results of our operations. Those two measures are Segment Margin and Available Cash before Reserves.

Segment Margin

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. A reconciliation of Segment Margin to income before income taxes is included in our segment disclosures in Note 9 to our Unaudited Condensed Consolidated Financial Statements.

Available Cash before Reserves

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

Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies.

Available Cash before Reserves 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 investment. Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

Available Cash before Reserves is net income as adjusted for specific items, the most significant of which are the addition of 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) and unrealized gains and losses on derivative transactions not designated as

Table of Contents

hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows.

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



	Three Months Ended September 30,
	2012			2011
	(in thousands)
Net income	$	31,194		$	19,088
Depreciation and amortization	14,838			14,706
Cash received from direct financing leases not included in income	1,278			1,167
Cash effects of sales of certain assets	13			3,269
Effects of distributable cash generated by equity method investees not included in income	5,613			3,701
Cash effects of equity-based compensation plans	(466		)	(306		)
Non-cash equity-based compensation expense (benefit)	2,001			(930		)
Expenses related to acquiring or constructing assets that provide new sources of cash flow	228			1,008
Unrealized gain on derivative transactions excluding fair value hedges	(75		)	(4,355		)
Maintenance capital expenditures	(701		)	(2,244		)
Non-cash tax benefit	(8,717		)	(48		)
Other items, net	653			1,985
Available Cash before Reserves	$	45,859		$	37,041

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2012 Quarter increased $112.1 million, or 14% from the 2011 Quarter. Additionally, our costs and expenses increased $111.6 million, or 14% between the two periods.

Our revenues for the nine months ended September 30, 2012 increased $515.2 million, or 23% from the nine months ended September 30, 2011. Costs and expenses increased $499 million, or 23% between the two nine month periods.

The majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs between the two third quarter and nine month periods is primarily attributable to increased volumes from our continuing operations and our acquisitions and, to a lesser extent, increases in the market prices for crude oil and petroleum products as described below.

Volumes increased in our supply and logistics segment by 30% quarter to quarter and 27% between the nine month periods as explained in our supply and logistics Segment Margin discussion below. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 3% to $92.22 per barrel in the third quarter of 2012, as compared to $89.76 per barrel in the third quarter of 2011. Average closing prices for WTI crude oil on the NYMEX were consistent between the nine month periods at approximately $96 per barrel.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and nine months ended September 30, 2012 and 2011 was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Pipeline transportation	$	23,295	$	16,030	$	69,427	$	50,639
Refinery services	18,983		17,992		53,510		54,887
Supply and logistics	23,651		18,909		66,075		44,233
Total Segment Margin	$	65,929	$	52,931	$	189,012	$	149,759

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,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	8,297		$	6,788		$	22,400		$	17,988
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees	8,927			2,288			27,114			12,326
CO₂ tariffs and revenues from direct financing leases of CO₂ pipelines	6,662			6,808			19,700			19,666
Sales of crude oil pipeline loss allowance volumes	2,369			1,790			7,152			5,418
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(4,461		)	(2,999		)	(11,384		)	(8,770		)
Payments received under direct financing leases not included in income	1,278			1,167			3,748			3,421
Other	223			188			697			590
Segment Margin	$	23,295		$	16,030		$	69,427		$	50,639

Volumetric Data (barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Jay	22,841			17,720			19,931			16,499
Texas	52,767			44,149			50,327			46,020
Mississippi	17,942			20,884			18,377			20,883
Offshore crude oil pipelines:
CHOPS⁽¹⁾	91,377			90,312			78,817			123,034
Poseidon ^{(1) (2)}	215,474			—			206,596			—
Odyssey ^{(1) (2)}	31,869			—			35,994			—
GOPL ⁽²⁾	8,300			—			16,979			—
CO₂ pipeline (Mcf/day):
Free State	188,165			192,041			177,527			166,302

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

(2) Acquired in January 2012.

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Pipeline transportation Segment Margin for the 2012 Quarter increased $7.3 million, or 45%. The significant components of this change were as follows:


•	Crude oil tariff revenues of onshore crude oil pipelines increased $1.5 million primarily due to upward tariff indexing of approximately 8.6% for our FERC-regulated pipelines effective in July 2012.

•

Segment Margin from our offshore crude oil pipelines increased $6.6 million reflecting a $7.7 million contribution from our interests in the Gulf of Mexico pipelines that we acquired in 2012. The contribution to Segment Margin by CHOPS declined by $1.1 million from the 2011 Quarter due to ongoing improvements being made by producers at several connected fields. Improvements at those fields were substantially completed late in the 2012 Quarter.


•	Onshore pipeline operating costs, excluding non-cash charges, increased $1.5 million due to pipeline integrity maintenance on the pipelines and employee compensation and related benefit costs.

Table of Contents

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011.

Segment Margin for our pipeline transportation segment increased $18.8 million, or 37%, between the nine month periods. The significant components of this change were as follows:


•	Crude oil tariff revenues of onshore crude oil pipelines increased $4.4 million primarily due to upward tariff indexing of 6.9% and 8.6% for our FERC-regulated pipelines effective in July 2011 and 2012, respectively.

•

Segment Margin from our offshore crude oil pipelines increased $14.8 million reflecting a $22.3 million contribution from our interests in the Gulf of Mexico pipelines that we acquired in 2012. The increase was partially offset by a decline of $7.5 million in the contribution to Segment Margin by CHOPS. Volumes transported on CHOPS decreased approximately 44,000 barrels per day as a result of improvements being made by producers at several connected production fields. Improvements at those fields were substantially completed late in the 2012 Quarter.


•	Revenues from sales of pipeline loss allowance volumes improved Segment Margin by $1.7 million due to an increase of approximately 13,225 barrels sold in the first nine months of 2012 compared to the first nine months of 2011.


•	Onshore pipeline operating costs, excluding non-cash charges, increased $2.6 million due to pipeline integrity maintenance on the pipelines and employee compensation and related benefit costs.

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Volumes sold (in Dry short tons "DST"):
NaHS volumes	34,372			33,396			107,321			106,709
NaOH (caustic soda) volumes	21,152			23,440			56,740			74,289
Total	55,524			56,836			164,061			180,998

Revenues (in thousands):
NaHS revenues	$	36,903		$	35,741		$	113,937		$	108,999
NaOH (caustic soda) revenues	11,936			11,430			32,211			33,673
Other revenues	1,539			3,811			5,178			9,227
Total external segment revenues	$	50,378		$	50,982		$	151,326		$	151,899

Segment Margin (in thousands)	$	18,983		$	17,992		$	53,510		$	54,887

Average index price for NaOH per DST ⁽¹⁾	$	579		$	540		$	566		$	492
Raw material and processing costs as % of segment revenues	46		%	44		%	48		%	43		%

(1) Source: Harriman Chemsult Ltd.

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Refinery services Segment Margin for the 2012 Quarter increased $1 million, or 6%. The significant components of this fluctuation were as follows:

•

NaHS revenues increased primarily as a function of the increase in the average index price for caustic soda and increased sales volumes. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point.

Table of Contents


•	Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition and utilization of caustic soda in our, and our customers', operations, and our logistics management helped offset these costs.

•

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

•

Average index prices for caustic soda increased to $579 per DST in the third quarter of 2012 compared to $540 per DST during the third quarter of 2011. 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 on our operating costs.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Refinery services Segment Margin decreased $1.4 million, or 3%, between the nine month periods. The significant components of this fluctuation were as follows:


•	Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda. In addition, in the first half of 2012, longer than anticipated refinery turnarounds at some of our largest refinery service locations resulted in increased costs as a result of processing at less efficient locations to ensure uninterrupted supplies to our customers.


•	NaHS revenues increased primarily as a function of the increase in the average index price for caustic soda. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point.

•

Caustic soda sales volumes decreased 24% primarily due to turnarounds at some of our refinery customers in the first half of 2012. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

•

Average index prices for caustic soda increased to $566 per DST in the first nine months of 2012 compared to $492 per DST during the first nine months of 2011. 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 on our operating costs.

Table of Contents

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,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Supply and logistics revenue	$	875,193		$	765,714		$	2,597,809		$	2,091,854
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(811,971		)	(714,710		)	(2,413,655		)	(1,965,687		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(39,927		)	(32,047		)	(117,846		)	(81,795		)
Other	356			(48		)	(233		)	(139		)
Segment Margin	$	23,651		$	18,909		$	66,075		$	44,233

Volumes of crude oil and petroleum products (barrels per day)	100,095			77,179			91,444			71,770

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

The average market prices of crude oil and petroleum products decreased 3% between the two quarterly periods; however that price volatility has a limited impact on our Segment Margin. Segment Margin for our supply and logistics segment increased by $4.7 million, or 25%, during the 2012 Quarter.

The increase in Segment Margin during the 2012 Quarter resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking and barge fleets. Our total volumes of crude oil and refined products increased 30% as a result of these expansions. Our operating costs, excluding non-cash charges, increased 25% between the two quarters due to our expanded trucking and barge fleets and increased utilization of such fleets.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Segment Margin for our supply and logistics segment increased $21.8 million, or 49%, between the nine month periods. Average market prices of crude oil and petroleum products were consistent at approximately $96 per barrel between the first nine months of 2011 and first nine months of 2012, however, as previously discussed, price volatility has a limited impact on our Segment Margin.

The increase in Segment Margin during the first nine months of 2012 resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking and barge fleets. Our total volumes of crude oil and refined products increased by 27% as a result of these expansions. Our operating costs, excluding non-cash charges, increased 44% between the two nine month periods due to our expanded trucking and barge fleets and increased utilization of such fleets.

Table of Contents

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	5,615	$	5,367	$	16,769	$	14,291
Segment	2,905		2,308		8,011		6,653
Equity-based compensation plan expense	1,627		222		4,138		866
Third party costs related to business development activities and growth projects	228		1,008		1,016		3,529
Total general and administrative expenses	$	10,375	$	8,905	$	29,934	$	25,339

Routine corporate and segment general and administrative expenses increased between the three and nine month periods as a result of salary and benefits expenses associated with increases in personnel to support our growth. Additionally, increases in the market price of our common units affected expense related to our equity-based compensation plans. A decrease in third party costs related to business and growth transactions resulted in a decrease of approximately $0.8 million and $2.5 million, for the three and nine month periods, respectively.

Depreciation and amortization expense



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Depreciation expense	$	9,202	$	5,960	$	27,246	$	17,838
Amortization of intangible assets	4,520		7,721		15,390		22,367
Amortization of CO2 volumetric production payments	1,116		1,025		2,811		2,895
Total depreciation and amortization expense	$	14,838	$	14,706	$	45,447	$	43,100

Total depreciation and amortization expense increased $0.1 million and $2.3 million, between the quarterly and nine month periods, respectively, as a result of an increases in depreciation expense, offset by decreases in amortization of intangible assets. Depreciation expense increased $3.2 million and $9.4 million, over the same periods primarily as a result of our recent acquisitions, including the black oil barge transportation assets in August 2011 and February 2012. Amortization of intangible assets decreased $3.2 million and $7.0 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. Generally, the amortization we record on those assets is greater in the initial years following their acquisition because our intangible assets are generally more valuable in the first years after an acquisition.

Interest expense, net



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	3,416		$	3,137		$	10,762		$	9,646
Interest expense, senior unsecured notes	6,938			5,032			19,688			14,930
Amortization of debt issuance costs and premium	825			792			2,655			2,102
Capitalized interest	(1,304		)	—			(2,394		)	—
Interest income	(2		)	(1		)	(14		)	(8		)
Net interest expense	$	9,873		$	8,960		$	30,697		$	26,670

Net interest expense increased $0.9 million between the quarterly periods and $4 million between the nine month periods primarily as a result of increased borrowings associated with acquisitions. Interest expense on our senior

Table of Contents

unsecured notes increased $1.9 million and $4.8 million, respectively, over the same periods as a result of issuing an additional $100 million of notes under the indenture in February 2012 to repay borrowings under our credit facility. Capitalized interest costs of $1.3 million and $2.4 million in the three and nine month periods, respectively, attributable to our growth capital expenditures and investments in the SEKCO pipeline joint venture (see below for more information) partially offset the increase in interest expense.

Income tax expense

Income tax expense decreased $8.7 million between the quarterly periods and $9.2 million between the nine month periods primarily due to the reversal of $8.2 million in uncertain tax positions as a result of tax audit settlements and the expiration of statutes of limitations.

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, 2012 and 2011 included an unrealized gain on derivative positions of $0.1 million and $4.4 million, respectively. Net income for the nine months ended September 30, 2012 and 2011 included an unrealized gain on derivative positions of $1.3 million and $4.6 million, respectively. Those amounts are included in Supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations and are not a component of Segment Margin.

Liquidity and Capital Resources

General

As of September 30, 2012, we had $504.4 million of borrowing capacity available under our $1 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations and borrowing availability under our credit facility.

Our primary cash requirements consist of:


•	Working capital, primarily inventories;


•	Routine operating expenses;


•	Capital expansion and maintenance projects;


•	Acquisitions of assets or businesses;


•	Interest payments related to outstanding debt; and


•	Quarterly cash distributions to our unitholders.

We continue to pursue a growth strategy that requires significant capital. In January 2012, we borrowed $205.6 million under our credit facility to acquire interests in several pipeline systems. See “Capital Expenditures and Business and Asset Acquisitions” below for more information related to our capital spending and acquisitions.

Capital Resources

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

In July 2012, we amended and restated our senior secured credit facility with a syndicate of banks to, among other things, increase the committed amount from $775 million to $1 billion and the accordion feature from $225 million to $300 million, giving us the ability to expand the size of the facility up to an aggregate of $1.3 billion for acquisitions or internal growth projects, subject to lender consent. The inventory financing sublimit tranche was increased from $125 million to $150 million, and the term of our credit facility was extended to July 25, 2017. This inventory tranche is designed to allow us to

Table of Contents

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.

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 1.75% to 2.75% on eurodollar borrowings and from 0.75% to 1.75% on alternate base rate borrowings.

•Letter of credit fees range from 1.75% to 2.75%.


•	The commitment fee on the unused committed amount will range from 0.375% to 0.50%.

We do not anticipate any of the lenders that participate in our credit facility being unable to satisfy their obligations under the credit facility.

In February 2012, we issued $100 million under our existing 7.875% senior unsecured notes indenture for which the net proceeds were used to repay borrowings under our credit facility. The notes were issued at 101% of face value at an effective interest rate of 7.682%. See Note 7 to our Unaudited Condensed Consolidated Financial Statements for more information.

In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. See Note 8 to our Unaudited Condensed Consolidated Financial Statements for more information.

At September 30, 2012, long-term debt totaled $833.9 million, consisting of $483 million outstanding under our credit facility (including $48.6 million borrowed under the inventory sublimit tranche) and a $350.9 million carrying amount of senior unsecured notes due in 2018.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facility and to fund capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

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 oil. In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility. See Note 11 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, 2012 and 2011.

Net cash flows provided by our operating activities for the nine months ended September 30, 2012 were $142.9 million compared to $39.1 million for the nine months ended September 30, 2011. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more or less cash. The increase in operating cash flow for the nine months ended September 30, 2012 compared to the same period in 2011 was primarily due to higher cash earnings and cash requirements to meet working capital needs.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our acquisition activities, internal growth projects and distributions we pay to our unitholders. We finance smaller internal growth projects and distributions primarily with cash generated by our operations. Acquisition activities and large internal growth projects have historically been funded with borrowings under our credit facility, equity issuances and the issuance of senior unsecured notes.

Table of Contents

Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets and other asset acquisitions for the nine months ended September 30, 2012 and 2011 is as follows:



	Nine Months Ended September 30,
	2012		2011
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets	$	261	$	231
Refinery services assets	799		1,219
Supply and logistics assets	1,660		1,935
Other assets	—		248
Total maintenance capital expenditures	2,720		3,633
Growth capital expenditures:
Pipeline transportation assets	37,184		3,033
Refinery services assets	1,496		102
Supply and logistics assets ⁽¹⁾	75,754		3,702
Information technology systems upgrade projects	1,175		3,516
Total growth capital expenditures	115,609		10,353
Total maintenance and growth capital expenditures	118,329		13,986
Capital expenditures for business combinations, net of liabilities assumed:
Offshore pipelines	205,576		—
Acquisition of FMT assets	—		143,489
Total business combinations capital expenditures	205,576		143,489
Capital expenditures related to equity investees ⁽²⁾	57,072		—
Total capital expenditures	$	380,977	$	157,475

(1) Includes the purchase of barge assets for $30.6 million (see below for more information).

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

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

Growth Capital Expenditures

In April 2011, we announced two projects to increase the services we provide to producers and refiners. We acquired three above-ground storage tanks located in Texas City, Texas and an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system. We also are constructing a truck station and tankage in West Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area. Once the refurbishment, tie-in and all interconnecting pipe are completed, estimated to be in the fourth quarter of 2012, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal. In addition, we have initiated construction of a 18-inch diameter loop of our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we expect will allow us to significantly expand our total service capabilities into the Texas City area by the second quarter of 2013.

During 2011, we also entered into an agreement to install a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in Tulsa, Oklahoma. The new facility, expected to be completed in the first quarter of 2013, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and is expected to result in potential additional capacity of 24,000 DST per year of NaHS.

We anticipate the costs of the projects listed above to be approximately $80 million in total, of which we have spent approximately $56.8 million since inception in 2011. We expect that the remaining costs for the projects will be spent primarily in the fourth quarter of 2012.

Table of Contents

We anticipate spending approximately $33 million to upgrade our refinery facilities in Wyoming and to bring the related pipeline back in service. We spent $4.4 million related to these projects during the first nine months of 2012.

In August 2012 we completed construction on the first phase of a new crude-by-rail unloading terminal connected to our existing crude oil pipeline at Walnut Hill, Florida. 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 anticipate the second phase of the terminal, which includes a 100,000 barrel storage tank and related equipment, to be completed in the fourth quarter of 2012 and cost approximately $4.5 million.

In February 2012, we purchased seven barges from Florida Marine Transporters, which previously had been subleased to us in connection with the acquisition of the black oil barge assets in August 2011. The cost of the seven barges totaled $30.6 million, which was funded with our credit facility.

Capital Expenditures Related to Business Combinations and Equity Investees

In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The purchase price, net of post-closing adjustments, was $205.6 million. We account for our ownership interests in Poseidon and Odyssey under the equity method of accounting. We accounted for our acquisition of GOPL using the acquisition method. See Note 2 in our Unaudited Condensed Consolidated Financial Statements for more information.

In December 2011, we formed Southeast Keathley Canyon Pipeline Company, LLC (or SEKCO) with Enterprise Products to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of Mexico. The new pipeline is expected to begin service by mid-2014. We expect to spend approximately $200 million for our share of the pipeline construction through 2014 and to reimburse Enterprise Products for our portion of previously incurred costs. We expect to pay approximately $80 million in 2012, of which we paid $57.1 million during the first nine months of 2012. The anchor producers, which have executed long-term transportation agreements, are responsible for most cost overruns and other costs incurred associated with weather-related delays.

Distributions to Unitholders

On November 14, 2012, we will pay a distribution of $0.4725 per common unit totaling $38.4 million with respect to the third quarter of 2012 to common unitholders of record on November 1, 2012. This is the twenty-ninth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 8 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, 2011.

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, 2011, 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. 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

Table of Contents

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 and 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;


•	shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum products, or CO2 or to whom we sell such products;


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


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


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


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


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


•	loss of key personnel;


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


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


•	our financial and commodity hedging arrangements;


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


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers or counterparties;


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


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


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

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011 and any other risk factors contained in our Current Reports on Form 8-K 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 2011 Annual Report on Form 10-K. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 12 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Table of Contents

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 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.

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, 2011. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011. On October 11, 2012, we filed a Current Report on Form 8-K that, among other things, included the risk factor set forth below. There have been no material changes to the risk factors since the filing of such Form 10-K and/or Form 8-K.

The Davison family exerts significant influence over us and may have conflicts of interest with us and may be permitted to favor its interests to the detriment of our other unitholders.

James E. Davison, Sr. and James E. Davison, Jr., each of whom is a director of our general partner, and certain of their family members and affiliates own approximately 17.2% of our Common Units - Class A and 76.9% of our Common Units - Class B. The Davison family is able to exert significant influence over us, including the ability to elect at least a majority of the members of our board of directors and the ability to control most matters requiring board approval, such as business strategies, mergers, business combinations, acquisitions or dispositions of significant assets, issuances of additional partnership securities, incurrence of debt or other financing and the payment of distributions. In addition, the continued existence of a controlling group may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire us, which may adversely affect the market price of our common units. Further, conflicts of interest may arise between us and other entities for which members of the Davison family serve as officers or directors. In resolving any conflicts that may arise, such members of the Davison family may favor the interests of another entity over our interests.

The Davison family owns, controls and has interests in diverse companies, some of which may (or could in the future) compete directly or indirectly with us. As a result, the Davison family's interests may not always be consistent with our interests or the interests of our other unitholders. The Davison family could also pursue acquisitions or business opportunities that may be complementary to our business. Our organizational documents allow the holders of our units (including affiliates, like the Davisons) to take advantage of such corporate opportunities without first presenting such opportunities to us. As a result, corporate opportunities that may benefit us may not be available to us in a timely manner, or at all. To the extent that conflicts of interest may arise among us and members of the Davison family, those conflicts may be resolved in a manner adverse to us or you. Other potential conflicts may involve, among others, the following situations:


•	our general partner is allowed to take into account the interest of parties other than us, such as one or more of its affiliates, in resolving conflicts of interest;


•	our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and its affiliates, retention of counsel, accountants and service providers, and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders; and

Table of Contents


•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to pay cash distributions to our unitholders.

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 3, 2011, File No. 001-12295).

3.6		Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295).

4.1		Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007, File No. 001-12295).

10.1		Third Amended and Restated Credit Agreement, dated as of July 25, 2012, 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 10.1 to Form 8-K dated July 31, 2012, File No. 001-12295).



31.1 *		Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.

31.2 *		Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.

32 *		Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.

101.INS *		XBRL Instance Document

101.SCH *		XBRL Schema Document

101.CAL *		XBRL Calculation Linkbase Document

101.LAB *		XBRL Label Linkbase Document

101.PRE *		XBRL Presentation Linkbase Document

101.DEF *		XBRL Definition Linkbase Document



*	Filed herewith

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:	November 6, 2012	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer

Genesis Energy L.P. - 10-Q quarterly report FY2012 Q3

What is the market capitalization of a company?

DISCLAIMER

Contact

Links