GEL Genesis Energy LP

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   ý     No   ¨

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

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Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding as of November 1, 2018 .

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GENESIS ENERGY, L.P.

TABLE OF CONTENTS

 

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Comprehensive Income	5
	Unaudited Condensed Consolidated Statements of Partners’ Capital	6
	Unaudited Condensed Consolidated Statements of Cash Flows	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
	1. Organization and Basis of Presentation and Consolidation	8
	2. Recent Accounting Developments	8
	3. Revenue Recognition	9
	4. Acquisition	15
	5. Inventories	16
	6. Fixed Assets and Mineral Leaseholds	17
	7. Equity Investees	18
	8. Intangible Assets	19
	9. Debt	20
	10. Partners' Capital, Mezzanine Capital and Distributions	21
	11. Net Income (Loss) Per Common Unit	22
	12. Business Segment Information	23
	13. Transactions with Related Parties	25
	14. Supplemental Cash Flow Information	27
	15. Derivatives	27
	16. Fair-Value Measurements	30
	17. Commitments and Contingencies	32
	18. Subsequent Events	32
	19. Condensed Consolidating Financial Information	32
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	59
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 3.	Defaults upon Senior Securities	60
Item 4.	Mine Safety Disclosures	60
Item 5.	Other Information	60
Item 6.	Exhibits	60
SIGNATURES		62

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)

 

	September 30, 2018				December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,878			$	9,041
Accounts receivable - trade, net	365,646				495,449
Inventories	85,722				88,653
Assets held for sale	255,519				—
Other	42,659				42,890
Total current assets	761,424				636,033
FIXED ASSETS, at cost	5,405,984				5,601,015
Less: Accumulated depreciation	(882,833		)		(734,986		)
Net fixed assets	4,523,151				4,866,029
MINERAL LEASEHOLDS, net of accumulated depletion	561,593				564,506
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	119,093				125,283
EQUITY INVESTEES	356,468				381,550
INTANGIBLE ASSETS, net of amortization	168,291				182,406
GOODWILL	325,046				325,046
OTHER ASSETS, net of amortization	120,102				56,628
TOTAL ASSETS	$	6,935,168			$	7,137,481
LIABILITIES AND CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	194,489			$	270,855
Accrued liabilities	235,517				185,409
Total current liabilities	430,006				456,264
SENIOR SECURED CREDIT FACILITY	1,220,700				1,099,200
SENIOR UNSECURED NOTES, net of debt issuance costs	2,460,486				2,598,918
DEFERRED TAX LIABILITIES	12,293				11,913
OTHER LONG-TERM LIABILITIES	275,823				256,571
Total liabilities	4,399,308				4,422,866
MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 23,914,890 and 22,411,728 issued and outstanding at September 30, 2018 and December 31, 2017, respectively	744,727				697,151
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 units issued and outstanding at September 30, 2018 and December 31, 2017	1,799,409				2,026,147
Accumulated other comprehensive loss	(604		)		(604		)
Noncontrolling interests	(7,672		)		(8,079		)
Total partners' capital	1,791,133				2,017,464
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	6,935,168			$	7,137,481

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

 

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
REVENUES:
Offshore pipeline transportation services	70,115				80,671				213,344				243,437
Sodium minerals and sulfur services	291,722				109,765				876,513				197,879
Marine transportation	56,296				48,534				161,410				152,038
Onshore facilities and transportation	327,145				247,144				972,207				714,974
Total revenues	745,278				486,114				2,223,474				1,308,328
COSTS AND EXPENSES:
Onshore facilities and transportation product costs	273,251				202,047				834,128				582,535
Onshore facilities and transportation operating costs	22,005				23,982				67,346				80,160
Marine transportation operating costs	44,195				35,789				126,259				111,980
Sodium minerals and sulfur services operating costs	229,204				79,365				685,219				133,335
Offshore pipeline transportation operating costs	17,753				18,690				53,533				54,682
General and administrative	24,209				19,409				49,412				38,723
Depreciation, depletion and amortization	91,876				63,732				244,811				176,453
Gain on sale of assets	(3,363		)		—				(3,363		)		(26,684		)
Total costs and expenses	699,130				443,014				2,057,345				1,151,184
OPERATING INCOME	46,148				43,100				166,129				157,144
Equity in earnings of equity investees	9,492				13,044				28,388				34,805
Interest expense	(58,819		)		(47,388		)		(172,864		)		(122,117		)
Other income (expense)	1,828				(2,276		)		(3,604		)		(2,276		)
Income (loss) before income taxes	(1,351		)		6,480				18,049				67,556
Income tax expense	(283		)		(320		)		(914		)		(878		)
NET INCOME (LOSS)	(1,634		)		6,160				17,135				66,678
Net loss attributable to noncontrolling interests	1,311				152				1,573				457
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	(323	)		$	6,312			$	18,708			$	67,135
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(17,635		)		(5,469		)		(51,780		)		(5,469		)
NET INCOME(LOSS) AVAILABLE TO COMMON UNITHOLDERS	$	(17,958	)		$	843			$	(33,072	)		$	61,666
NET INCOME(LOSS) PER COMMON UNIT (Note 11):
Basic and Diluted	$	(0.15	)		$	0.01			$	(0.27	)		$	0.51
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	122,579				122,579				122,579				121,198

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Net income (loss)	$	(1,634	)		$	6,160			$	17,135			$	66,678
Other comprehensive loss:
Change in benefit plan liability	—				—				—				—
Total Comprehensive income (loss)	(1,634		)		6,160				17,135				66,678
Comprehensive loss attributable to non-controlling interests	1,311				152				1,573				457
Comprehensive income (loss) attributable to Genesis Energy, L.P.	$	(323	)		$	6,312			$	18,708			$	67,135

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

 

	Number of Common Units			Partners’ Capital				Noncontrolling Interest				Accumulated Other Comprehensive Loss				Total
Partners’ capital, December 31, 2017	122,579			$	2,026,147			$	(8,079	)		$	(604	)		$	2,017,464
Impact of adoption of ASC 606	—			(3,550		)		—				—				(3,550		)
Partners’ capital, January 1, 2018	122,579			2,022,597				(8,079		)		(604		)		2,013,914
Net income (loss)	—			18,708				(1,573		)		—				17,135
Cash distributions to partners	—			(191,224		)		—				—				(191,224		)
Cash contributions from noncontrolling interests	—			—				1,980				—				1,980
Distributions to Class A Convertible Preferred unitholders	—			(50,672		)		—				—				(50,672		)
Partners' capital, September 30, 2018	122,579			$	1,799,409			$	(7,672	)		$	(604	)		$	1,791,133
	Number of Common Units			Partners’ Capital				Noncontrolling Interest				Accumulated Other Comprehensive Loss				Total
Partners’ capital, January 1, 2017	117,979			$	2,130,331			$	(10,281	)		$	—			$	2,120,050
Net income (loss)	—			67,135				(457		)		—				66,678
Cash distributions to partners	—			(260,586		)		—				—				(260,586		)
Cash contributions from noncontrolling interests	—			—				1,850				—				1,850
Issuance of common units for cash, net	4,600			140,513				—				—				140,513
Partners' capital, September 30, 2017	122,579			$	2,077,393			$	(8,888	)		$	—			$	2,068,505

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

	Nine Months Ended September 30,
	2018				2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	17,135			$	66,678
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	244,811				176,453
Provision for leased items no longer in use	—				12,589
Gain on sale of assets	(3,363		)		(26,684		)
Amortization and write-off of debt issuance costs and discount	9,489				8,154
Amortization of unearned income and initial direct costs on direct financing leases	(9,847		)		(10,374		)
Payments received under direct financing leases	15,501				15,501
Equity in earnings of investments in equity investees	(28,388		)		(34,805		)
Cash distributions of earnings of equity investees	28,992				34,454
Non-cash effect of long-term incentive compensation plans	3,240				(5,524		)
Deferred and other tax liabilities	380				508
Unrealized loss on derivative transactions	1,285				3,040
Other, net	999				(7,338		)
Net changes in components of operating assets and liabilities ( Note 14 )	27,330				(26,262		)
Net cash provided by operating activities	307,564				206,390
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(152,868		)		(182,653		)
Cash distributions received from equity investees - return of investment	26,042				25,917
Investments in equity investees	(2,960		)		—
Acquisitions	—				(1,325,759		)
Contributions in aid of construction costs	—				124
Proceeds from asset sales	36,859				39,204
Net cash used in investing activities	(92,927		)		(1,443,167		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	759,800				1,247,700
Repayments on senior secured credit facility	(638,300		)		(1,153,400		)
Proceeds from issuance of senior unsecured notes	—				550,000
Proceeds from issuance of Class A convertible preferred units, net	—				729,958
Repayment of senior unsecured notes	(145,170		)		—
Debt issuance costs	(242		)		(17,808		)
Issuance of common units for cash, net	—				140,513
Contributions from noncontrolling interests	1,980				1,850
Distributions to common unitholders	(191,224		)		(260,586		)
Other, net	1,356				1,215
Net cash provided by (used in) financing activities	(211,800		)		1,239,442
Net increase in cash and cash equivalents	2,837				2,665
Cash and cash equivalents at beginning of period	9,041				7,029
Cash and cash equivalents at end of period	$	11,878			$	9,694

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States and the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, soda ash businesses, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. We 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.

On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing and selling business (our "Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of Class A Convertible Preferred units (our "preferred units"), a $550 million public offering of notes, our revolving credit facility, and cash on hand. We report the results of our Alkali Business in our sodium minerals and sulfur services segment, which includes our Alkali Business as well as our legacy refinery services operations.

We currently manage our businesses through the following four divisions that constitute our reportable segments:

•	Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;

•	Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as 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");

•	Onshore facilities and transportation, which include terminalling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO 2 ; and

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

Basis of Presentation and Consolidation

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

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, 2017 .

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

2. Recent Accounting Developments

Recently Issued

We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. The adoption date for our material equity method investment in the Poseidon Oil Pipeline Company, LLC will follow the non-public business entity adoption date of January 1, 2019 for its stand-alone financial statements. Refer to Note 3 for further details.

In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also

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requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption.

Our team has reviewed the practical expedients we expect to apply as part of the implementation of the new standard. In July 2018, the FASB issued ASU 2018-11 as a targeted improvement on the new leasing standard, which provides an additional (and optional) method to adopt the new leasing standard. Under this new transition method, an entity will only apply the new lease standard at the date of adoption while comparative periods will be presented under the previous lease guidance (Topic 840). We plan to adopt this method for our transition.

Additionally, we currently plan to elect to take the "package" of practical expedients set out in the standard, which must be elected together. The items within the package stipulate that an entity need not reassess: (1) if expired or existing contracts contain leases, (2) lease classification for previously assessed leases under ASC 840, and (3) initial direct costs for existing leases. The standard allows for a practical expedient relating to the separation of lease and non-lease components when applying ASC 842. This expedient is made as a policy election based on asset class and is applied to all items within the class. We have elected to adopt this expedient as part of our transition and implementation. Our team is still evaluating which asset classes will have such a policy election. As it relates to easements and right of ways, a practical expedient is permitted where companies can elect to continue to apply its current accounting policy for all land easements that exist or expire prior to the adoption date. We plan to take this expedient and will continue to apply our current accounting treatment to existing easements. An additional expedient offered by the new standard is the hindsight expedient, which allows an entity to use hindsight when determining a lease term, including options to renew or terminate as well as impairment for right-of-use assets. We do not plan to utilize this practical expedient.

Lastly, our implementation team is in the process of identifying our complete lease population and evaluating the application of this guidance.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We have adopted this guidance as of January 1, 2018 using the retrospective transition method to each period presented on the Consolidated Statements of Cash Flows. We reclassified $11.4 million from operating cash flows to investing cash flows for the nine months ended September 30, 2017.

In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715). ASU 2017-07 requires employers to separate the service cost component from the other components of net benefit cost in the period. The new standard requires the other components of net benefit costs (excluding service costs), be reclassified to "Other expense" from "General and administrative." We adopted this standard as of January 1, 2018. This standard is applied retrospectively. The effect was not material to our financial statements for the three and nine months ended September 30, 2018.

3. Revenue Recognition

Adoption of ASC 606 and its related Transition Effects

The modified retrospective method of adoption required us to apply ASC 606 to all new revenue contracts entered into after January 1, 2018 and revenue contracts that were not completed as of January 1, 2018. Our consolidated revenues for periods prior to January 1, 2018 were not revised and the cumulative effect of our adoption of ASC 606 was recorded as an adjustment to partners' capital at January 1, 2018. Based on this application, the following adjustments were made to our consolidated balance sheet as of January 1, 2018:

	December 31, 2017				Adjustments				January 1, 2018
ASSETS
Accounts receivable - trade, net	$	495,449			$	(48,028	)		$	447,421
Inventories	88,653				5,138				93,791
Other assets, net of amortization	56,628				59,204				115,832
LIABILITIES AND CAPITAL
Other long-term liabilities	256,571				19,864				276,435
Partners' capital	2,026,147				(3,550		)		2,022,597

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Current Impact of New Revenue Recognition Guidance

The tables below summarize the impact of adoption on our unaudited condensed consolidated balance sheet and statement of operations as of and for the three and nine months ended September 30, 2018:

	As of September 30, 2018
Unaudited Condensed Consolidated Balance Sheet	As Reported				Without adoption of ASC 606				Effect of Change Increase/(Decrease)
ASSETS
Accounts receivable-trade, net	$	365,646			$	413,674			$	(48,028	)
Inventories	85,722				83,329				2,393
Other Assets, net of amortization	120,102				50,742				69,360
LIABILITIES AND CAPITAL
Other Long-Term Liabilities	275,823				251,075				24,748
Partners' Capital	1,799,409				1,800,432				(1,023		)

	Three months ended September 30, 2018												Nine months ended September 30, 2018
Unaudited Condensed Consolidated Statement of Operations	As Reported				Without adoption of ASC 606				Effect of Change Increase/(Decrease)				As Reported				Without adoption of ASC 606				Effect of Change Increase/(Decrease)
Offshore pipeline transportation services	$	70,115			$	69,323			$	792			$	213,344			$	208,073			$	5,271
Sodium minerals and sulfur services	291,722				268,207				23,515				876,513				801,323				75,190
Marine transportation	56,296				56,296				—				161,410				161,410				—
Onshore facilities and transportation	327,145				327,145				—				972,207				972,207				—
Total revenues	745,278				720,971				24,307				2,223,474				2,143,013				80,461
Onshore facilities and transportation product costs	273,251				273,251				—				834,128				834,128				—
Onshore facilities and transportation operating costs	22,005				22,005				—				67,346				67,346				—
Marine transportation operating costs	44,195				44,195				—				126,259				126,259				—
Sodium minerals and sulfur services operating costs	229,204				204,013				25,191				685,219				607,285				77,934
Offshore pipeline transportation operating costs	17,753				17,753				—				53,533				53,533				—
OPERATING INCOME	46,148				47,032				(884		)		166,129				163,602				2,527

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The effects of changes pursuant to ASC 606 in the tables above are attributable to our offshore pipeline transportation services operating segment and our sodium minerals and sulfur services operating segment.

In our offshore pipeline transportation services segment, we have certain contracts with customers that contain tiered pricing structures that are dependent upon reaching certain cumulative milestones of throughput volumes on our pipelines. In addition, we have a contract that contains fixed and variable consideration for us to stand ready and provide reservation capacity for a fixed minimum quantity on our pipeline. Pursuant to the new guidance, we have allocated our estimated total transaction price over the life of the contract to the related performance obligation and recognized the effects in our Consolidated Financial Statements. In our sodium minerals and sulfur services operating segment, specifically our legacy refinery services business, we have two distinct performance obligations, including the completion of our refinery sulfur removal process, for which we receive in-kind consideration, and our sale of NaHS to our customers. Due to this, we have recorded revenue and the related cost of sales in the Consolidated Financial Statements for the three and nine months ended September 30, 2018 for services performed for the in-kind consideration for our services. Further discussion of our performance obligations by type and segment are below.

Revenue from Contracts with Customers

The following table reflects the disaggregation of our revenues by major category for the three and nine months ended September 30, 2018:

	Three Months Ended September 30,
	Onshore Facilities & Transportation				Sodium Minerals & Sulfur Services				Offshore Pipeline Transportation				Marine Transportation				Consolidated
Fee-based revenues	$	42,188			$	—			$	70,115			$	56,296			$	168,599
Product Sales	284,957				268,207				—				—				553,164
Refinery Services	—				23,515				—				—				23,515
	$	327,145			$	291,722			$	70,115			$	56,296			$	745,278

	Nine Months Ended September 30,
	Onshore Facilities & Transportation				Sodium Minerals & Sulfur Services				Offshore Pipeline Transportation				Marine Transportation				Consolidated
Fee-based revenues	$	107,536			$	—			$	213,344			$	161,410			$	482,290
Product Sales	864,671				801,323				—				—				1,665,994
Refinery Services	—				75,190				—				—				75,190
	$	972,207			$	876,513			$	213,344			$	161,410			$	2,223,474

The Company recognizes revenue upon the satisfaction of its performance obligations under its contracts. The timing of revenue recognition varies for the revenue streams described in more detail below. In general, the timing includes recognition of revenue over time as services are being performed as well as recognition of revenue at a point in time, for delivery of products.

Fee-based Revenues

We provide a variety of fee-based transportation and logistics services to our customers across several of our reportable segments as outlined below.

Service contracts generally contain a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over the contract period, and therefore qualify as a single performance obligation that is satisfied over time. The customer receives and consumes the benefit of our services simultaneous with the provision of those services.

Offshore Pipeline Transportation

Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of natural gas or per barrel of crude oil) gathered, transported, or processed for each volume delivered. Fees are based either on contractual arrangements or tariffs regulated by the FERC. These contracts include a single performance obligation to stand ready, on a

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monthly basis, to provide capacity on our assets. Revenue associated with these fee-based services is recognized as volumes are delivered over the performance obligation period.

In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer regardless of the volume the customer actually delivers to the platform or through the pipeline.

In addition to these offshore pipeline transportation services revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, the performance obligation satisfied by us does not change throughout the life of the contract. Therefore revenue is recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously recognized revenue will not occur throughout the life of the contract. These estimates will be reassessed at each reporting period as required. Billings to our customers are reflected at the contract rate. The difference between the consideration received from our customers from invoicing compared to the revenue recognized creates a contract asset or liability. In circumstances where the estimated average contract rate is less than the billed current price tier in the contract, we will recognize a contract liability. In circumstances where the estimated average contract rate is higher than the billed current price tier in the contract, we will recognize a contract asset.

Onshore Facilities and Transportation

Within our onshore facilities and transportation segment, we provide our customers with pipeline transportation, terminalling services, and rail loading/unloading services, among others, primarily on a per barrel fee basis.

Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff and some contain minimum throughput provisions which reset within one year. We recognize revenues for transportation and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible transportation and other services are recognized over time as the product is delivered to the agreed upon delivery point or at the point of receipt because they specifically relate to our efforts to transfer the distinct services.

Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or regulated tariff pricing. Consideration to be received by us under these contracts is variable, as the total volume of the commodity to be transported is unknown at contract inception. At the end of a day or month (as specified in the contract), both the price and volume are known (or “fixed”) in order to allow us to accurately calculate the amount of consideration we are entitled to invoice. The measurement of these services and invoicing occurs on a monthly basis.

Pipeline Loss Allowances

In order to compensate us for bearing the risk of volumetric losses of crude oil in transit in our pipelines (for our onshore and offshore pipelines) due to temperature, crude quality, and the inherent difficulties of measurement of liquids in a pipeline, our tariffs and agreements include the right for us to make volumetric deductions from the customer for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances ("PLA"). We compare these allowances to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or a reduction of revenue. As the allowance is related to our pipeline transportation services, the performance obligation is the obligation to transport and deliver the barrels and is considered a single obligation.

When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand and record a liability for the purchase of crude oil required to replace the lost volumes. Under ASC 606, we record excess oil as non-cash consideration at the lower of the recorded value or the market value and include this amount in the transaction price. The crude oil in inventory can then be sold at current prevailing market prices, resulting in additional revenue if the sales price exceeds the inventory value when control transfers to the customer.

Marine Transportation

Our marine transportation business consists of revenues from the inland and offshore marine transportation of heavy refined petroleum products, asphalt and crude oil, using our barges or vessels. This revenue is recognized over the passage of

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time of individual trips as determined on an individual contract basis. Revenue from these contracts is typically based on a set day-rate or a set fee per cargo movement. The costs of fuel and certain other operational costs may be directly reimbursed by the customer, if stipulated in the contract.

A performance obligation is driven by providing transportation services using our vessels for a single day either under a term or spot based contract. The transaction price is usually fixed per the contract either as a day rate or as a lump sum to be allocated over days required to complete the service. Revenue is recognizable as the transportation service utilizing our vessels occurs, as the customer simultaneously receives and consumes these services as they are provided. If provided in the contract, certain items such as fuel or operational costs can be rebilled to the customer in the same period in which the costs are incurred. In the event the timing of a trip to provide our services crosses a reporting period under a lump sum fee contract, the revenue earned is accrued based on the progress completed in the current period on the related performance obligation as we are entitled to payment for each day. Customer invoicing occurs at the completion of a trip, or earlier at the customer’s request.

Product Sales

Sodium Minerals and Sulfur Services

Product sales in our sodium minerals and sulfur services segment primarily involve the sales of caustic soda, NaHS, soda ash and other alkali products. As it relates to revenue recognition, these sales transactions contain a single performance obligation, which is the delivery of the product to the customer at the agreed upon point of sale. For some transactions, control of product transfers to the customer at the shipping point, but we are obligated to arrange for shipment of the product as directed by the customer. Rather than treat these shipping activities as separate performance obligations, our policy is to account for them as fulfillment costs in accordance with ASC 606.

The transaction price for these product sales are determined by specific contracts, typically at a fixed rate or based on a market or indexed rate. This pricing is known, or is “fixed,” at the time of revenue recognition. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing. The entirety of the transaction price is allocated to the performance obligation which is delivery of the product at the agreed upon point of sale. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations.

Onshore Facilities and Transportation

Product sales in our onshore facilities and transportation segment primarily involve the sales of crude oil and petroleum products. These contracts contain a single performance obligation, which is the delivery of the product to the customer at a specified location. These contracts are settled on a monthly basis for term contracts, or on a spot basis. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing.

Pricing is designated within the contracts and is either fixed, index-based or formulaic, utilizing an average price for the month or for a specified range of days, regardless of when delivery occurs. In either case, pricing is known at the time of invoicing. The entirety of the consideration is allocated to a single performance obligation which is delivery of the product to a specified location. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations.

Refinery Services

Our refinery services business primarily provides sulfur extraction services to refiners’ high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses caustic soda to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. The technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. Units of NaHS are produced ratably as a gas stream is processed. We obtain control and ownership of the NaHS immediately upon production which constitutes the sole consideration received for our sulfur removal services. We later market this product to third parties as part of our product sales, as described above. As part of some of our arrangements, we pay a refinery access fee (“RSA fee”) for any benefits received by virtue of our plant’s proximity to the customer’s refinery. Our RSA fee is recorded as a reduction of revenue.

Providing sulfur removal services is the singular performance obligation in our refinery service agreements. As our customers simultaneously receive and consume the refinery service benefits, control is transferred and revenue is recognized over time based on the extent of progress towards completion of the performance obligations. We use units of NaHS produced during a period to measure progress as the amount we receive corresponds directly with the efforts to provide our services completed to date. The transaction price for each performance obligation is determined using the fair value of a unit of NaHS on the contract inception date for each refinery services agreement. Accordingly, we record the value of NaHS received as non-cash consideration in inventory until it is subsequently sold to our customers (see Product Sales, above).

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Contract Assets and Liabilities

The table below depicts our contract asset and liability balances at January 1, 2018 and September 30, 2018:

	Contract Assets				Contract Liabilities
	Non-Current				Non-Current
Balance at January 1, 2018	$	59,204			$	19,864
Balance at September 30, 2018	69,360				24,748

During the nine months ended September 30, 2018, there were no balances that were previously classified as contract liabilities at the beginning of the period that were recognized as revenues. Accounts receivable-trade, net does not include consideration received in kind from our refinery services process. We did not have any contract modifications during the period that would affect our contract asset and liability balances.

Transaction Price Allocations to Remaining Performance Obligations

We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance obligations as of September 30, 2018. However, ASC 606 does provide the following practical expedients and exemptions that we utilized:

1)	Performance obligations that are part of a contract with an expected duration of one year or less;

2)	Revenue recognized from the satisfaction of performance obligations where we have a right to consideration in an amount that corresponds directly with the value provided to customers; and

3)	Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that is part of a series.

We apply these practical expedients and exemptions to our revenue streams recognized over time. The majority of our contracts qualify for one of these expedients or exemptions. After considering these practical expedients and identifying the remaining contract types that involve revenue recognition over a long-term period and include long-term fixed consideration (adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance obligations. As it relates to our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long term period. Therefore, we have allocated the remaining contract value (as estimated and discussed above) to future periods.

Similarly, in our marine transportation segment, our contract related to our M/T American Phoenix contains minimum fixed consideration over the life of the contract, which ends in September 2020. In our onshore facilities and transportation segment, we have certain contractual arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines and related assets. 

The following chart depicts how we expect to recognize revenues for future periods related to these contracts:

	Offshore Pipeline Transportation			Marine Transportation			Onshore Facilities and Transportation
Remainder of 2018	$	21,154		$	6,808		$	14,297
2019	73,918			27,010			57,090
2020	50,883			20,128			57,090
2021	34,261			—			20,139
2022	22,558			—			4,283
Thereafter	134,623			—			—
Total	$	337,397		$	53,946		$	152,899

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4. Acquisition

Acquisition

Alkali Business

On September 1, 2017 , we acquired our Alkali Business for approximately $1.325 billion (inclusive of approximately $105 million in working capital). Our Alkali Business produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. To finance that transaction and the related costs, we used proceeds from (i) a $550.0 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance discount and underwriting fees, (ii) a $750 million private placement of our preferred units in September 2017, generating net proceeds of $726.2 million , (iii) borrowings under our revolving credit facility and (iv) cash on hand.

We have reflected the financial results of our Alkali Business in our sodium minerals and sulfur services segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed. Those fair values were developed by management with the assistance of a third-party valuation firm. Our finalized purchase price allocation remains unchanged from what was disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017 , the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:

	Three Months Ended September 30, 2018				Nine Months Ended September 30, 2018
Revenues	$	208,742			628,672
Net Income Attributable to Genesis Energy, L.P.	$	29,536			91,680

The table below presents selected unaudited pro forma financial information incorporating the historical results of our Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2017 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of the Tronox trona and trona-based exploring, mining, processing, producing, marketing and selling business and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Alkali Business acquisition been completed on January 1, 2017 . Pro forma net income includes the effects of distributions on our preferred units and interest expense on incremental borrowings. The dilutive effect of our preferred units is calculated using the if-converted method.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017				2017
Pro forma consolidated financial operating results:
Revenues	$	615,289			$	1,829,389
Net Income Attributable to Genesis Energy, L.P.	10,955				92,880
Net Income (Loss) Available to Common Unitholders	(6,178		)		42,575
Basic and diluted earnings per common unit:
As reported net income per common unit	$	0.01			$	0.51
Pro forma net income (loss) per common unit	$	(0.05	)		$	0.35

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Inventories

The major components of inventories were as follows:

	September 30, 2018				December 31, 2017
Petroleum products	$	21,082			$	8,731
Crude oil	16,493				29,873
Caustic soda	8,030				5,755
NaHS	9,682				8,277
Raw materials - Alkali operations	5,592				4,550
Work-in-process - Alkali operations	2,820				7,355
Finished goods, net - Alkali operations	11,526				14,075
Materials and supplies, net - Alkali operations	10,496				10,030
Other	1				7
Total	$	85,722			$	88,653

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Mineral Leaseholds

Our Mineral Leaseholds, relating to our acquired Alkali Business, consist of the following:

	September 30, 2018				December 31, 2017
Mineral leaseholds	$	566,019			$	566,019
Less: Accumulated depletion	(4,426		)		(1,513		)
Mineral leaseholds, net	$	561,593			$	564,506

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Depreciation expense	$	85,282			$	57,117			$	224,546			$	157,438
Depletion expense	722				381				2,913				381

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Remainder of	2018	$	2,459
	2019	$	9,057
	2020	$	8,710
	2021	$	9,302
	2022	$	9,935

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Genesis’ share of operating earnings	$	13,364			$	16,986			$	40,144			$	46,631
Amortization of excess purchase price	$	(3,872	)		(3,942		)		(11,756		)		(11,826		)
Net equity in earnings	$	9,492			$	13,044			$	28,388			$	34,805
Distributions received	$	17,044			$	20,180			$	55,034			$	60,371

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	September 30, 2018												December 31, 2017
	Gross Carrying Amount				Accumulated Amortization				Carrying Value				Gross Carrying Amount				Accumulated Amortization				Carrying Value
Sodium minerals and sulfur services:
Customer relationships	$	94,654			$	94,114			$	540			$	94,654			$	92,493			$	2,161
Licensing agreements	38,678				38,141				537				38,678				36,528				2,150
Non-compete agreement	800				289				511				800				89				711
Segment total	134,132				132,544				1,588				134,132				129,110				5,022
Onshore Facilities & Transportation:
Customer relationships	35,430				35,113				317				35,430				35,082				348
Intangibles associated with lease	13,260				5,288				7,972				13,260				4,933				8,327
Segment total	48,690				40,401				8,289				48,690				40,015				8,675
Marine contract intangibles	27,000				15,750				11,250				27,000				11,700				15,300
Offshore pipeline contract intangibles	158,101				26,350				131,751				158,101				20,109				137,992
Other	31,149				15,736				15,413				28,900				13,483				15,417
Total	$	399,072			$	230,781			$	168,291			$	396,823			$	214,417			$	182,406

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	September 30, 2018												December 31, 2017
	Principal				Unamortized Discount and Debt Issuance Costs (1)				Net Value				Principal				Unamortized Discount and Debt Issuance Costs (1)				Net Value
Senior secured credit facility	$	1,220,700			$	—			$	1,220,700			$	1,099,200			$	—			$	1,099,200
5.750% senior unsecured notes due February 2021	—				—				—				145,170				1,303				143,867
6.750% senior unsecured notes due August 2022	750,000				13,601				736,399				750,000				16,077				733,923
6.000% senior unsecured notes due May 2023	400,000				4,891				395,109				400,000				5,691				394,309
5.625% senior unsecured notes due June 2024	350,000				5,044				344,956				350,000				5,717				344,283
6.500% senior unsecured notes due October 2025	550,000				8,546				541,454				550,000				9,462				540,538
6.250% senior unsecured notes due May 2026	450,000				7,432				442,568				450,000				8,002				441,998
Total long-term debt	$	3,720,700			$	39,514			$	3,681,186			$	3,744,370			$	46,252			$	3,698,118

(1)	Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Unaudited Condensed Consolidated Balance Sheet) were $11.6 million and $14.1 million as of September 30, 2018 and December 31, 2017, respectively.

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Distribution For		Date Paid		Per Unit Amount				Total Amount
2017
1 st  Quarter		May 15, 2017		$	0.7200			$	88,257
2 nd  Quarter		August 14, 2017		$	0.7225			$	88,563
3 rd  Quarter		November 14, 2017		$	0.5000			$	61,290
4 th  Quarter		February 14, 2018		$	0.5100			$	62,515
2018
1 st  Quarter		May 15, 2018		$	0.5200			$	63,741
2 nd  Quarter		August 14, 2018		$	0.5300			$	64,967
3 rd   Quarter		November 14, 2018	(1)	$	0.5400			$	66,193

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		As of September 30,
Mezzanine Capital Balance		2018
Balance as of December 31, 2017		$	697,151
Distributions paid-in-kind		50,671
Allocation of Distributions paid in-kind to Preferred Distribution Rate Reset Election ( Note 16 )		(3,095		)
Balance as of September 30, 2018		$	744,727

		Nine months ended September 30,
Number of Class A Convertible Preferred Units		2018
Balance as of December 31, 2017		22,411,728
Distributions paid-in-kind		1,503,162
Balance as of September 30, 2018		23,914,890

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•	Offshore pipeline transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico;

•	Sodium minerals and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, NaHS;

•	Onshore facilities and transportation – terminalling, blending, storing, marketing and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and CO 2 ;and

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

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(a)	A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for the periods is presented below.

(b)	Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same.

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

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

(2)	Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts.

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Revenues:
Sales of CO 2  to Sandhill Group, LLC (1)	$	—			$	750			$	1,233			$	2,153
Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2)	3,021				3,170				9,260				9,236
Revenues from product sales to ANSAC	90,433				31,774				275,167				31,774
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165			$	165			$	495			$	495
Charges for services from Poseidon Oil Pipeline Company, LLC (2)	247				254				746				744
Charges for services from ANSAC	1,393				454				4,427				454

 

(1)	We owned a 50% interest in Sandhill Group, LLC which was sold during the three months ended September 30, 2018.

(2)	We own 64% interest in Poseidon Oil Pipeline Company, LLC.

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	September 30,				December 31,
	2018				2017
Receivables:
ANSAC	$	63,431			$	74,490
Payables:
ANSAC	$	1,366			$	1,223

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		Sell (Short) Contracts				Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		50				—
Weighted average contract price per bbl		$	69.14			$	—
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)		315				221
Weighted average contract price per bbl		$	68.70			$	68.15
Natural gas swaps:
Contract volumes (10,000 MMBTU)		502				—
Weighted average price differential per MMBTU		$	0.65			$	—
Natural gas futures:
Contract volumes (10,000 MMBTU)		54				507
Weighted average contract price per MMBTU		$	3.01			$	2.82
Diesel futures:
Contract volumes (1,000 bbls)		15				5
Weighted average contract price per bbl		$	2.29			$	2.23
NYM RBOB Gas futures:
Contract volumes (42,000 gallons)		22				12
Weighted average contract price per gallon		$	2.03			$	2.00
Fuel oil futures:
Contract volumes (1,000 bbls)		255				—
Weighted average contract price per bbl		$	65.90			$	—
Crude oil options:
Contract volumes (1,000 bbls)		50				10
Weighted average premium received		$	1.34			$	0.31

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

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			Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location		Three Months Ended September 30,								Nine Months Ended September 30,
			2018				2017				2018				2017
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs		$	759			$	(3,399	)		$	(2,028	)		$	8,433
Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs		(1,157		)		(1,329		)		(6,833		)		650
Total commodity derivatives			$	(398	)		$	(4,728	)		$	(8,861	)		$	9,083
Natural Gas Swap Liability	Sodium minerals and sulfur services operating costs		$	229			$	—			$	44			$	—
Preferred Distribution Rate Reset Election	Other income (expense)		$	1,826			$	(2,276	)		$	(268	)		$	(2,276	)

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

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

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

		Fair Value at												Fair Value at
		September 30, 2018												December 31, 2017
Recurring Fair Value Measures		Level 1				Level 2				Level 3				Level 1				Level 2				Level 3
Commodity derivatives:
Assets		$	1,509			$	170			$	—			$	559			$	—			$	—
Liabilities		$	(3,109	)		$	(28	)		$	—			$	(2,066	)		$	—			$	—
Preferred Distribution Rate Reset Election		$	—			$	—			$	(48,572	)		$	—			$	—			$	(45,209	)

Rollforward of Level 3 Fair Value Measurements

The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3:

	Nine months ended September 30,
	2018
Balance as of December 31, 2017	$	(45,209	)
Change in fair value included in earnings	(268		)
Allocation of Distributions Paid-in-kind	(3,095		)
Balance as of September 30, 2018	$	(48,572	)

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

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K for the year ended December 31, 2017 .

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

•	Overview

•	Results of Operations

•	Liquidity and Capital Resources

•	Non-GAAP Financial Measures

•	Commitments and Off-Balance Sheet Arrangements

•	Forward Looking Statements

Overview

On September 1, 2017, we completed the $1.325 billion acquisition of our trona and trona-based exploring, mining, processing, producing, marketing and selling business (our "Alkali Business"). Our Alkali Business is the largest producer in the world of natural soda ash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of our preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand.

On August 7, 2018, we granted a third party a time-limited option to acquire our Powder River Basin midstream assets in exchange for an option payment of $30 million. On October 11, 2018, we completed the sale and received total net proceeds of approximately $300 million, inclusive of the $30 million option payment.

We reported net loss attributable to Genesis Energy, L.P. of $0.3 million during the three months ended September 30, 2018 (“ 2018 Quarter”) compared to net income attributable to Genesis Energy, L.P. of $6.3 million during the three months ended September 30, 2017 (“2017 Quarter”). The 2018 Quarter included three months of contribution related to our Alkali Business that we acquired on September 1, 2017, which contributed to our overall $ 36.7 million increase to segment margin during the 2018 Quarter relative to the 2017 Quarter. Additionally, we had a gain on sale of assets of $3.4 million and an increase in other income (expense) of approximately $4.1 million primarily due to the valuation of the embedded derivative associated with our convertible preferred units. Net income was negatively impacted in the 2018 Quarter by an increase in interest and depreciation expense, primarily driven by our acquisition of our Alkali Business, an increase in general and administrative costs during the 2018 Quarter relative to the 2017 Quarter by approximately $4.8 million, and a decrease in equity in earnings of equity investees of approximately $3.6 million.

Cash flow from operating activities was $156.7 million for the 2018 Quarter compared to $30.1 million for the 2017 Quarter. The increase in cash flows from operating activities for the 2018 Quarter was primarily driven by positive working capital effects during the period and an increase in our reported segment margin during the 2018 Quarter.

Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") was $112.7 million for the 2018 Quarter, an increase of $21.6 million , or 23.8% , from the 2017 Quarter. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Segment Margin (as defined below in "Non-GAAP Financial Measures") was $183.2 million for the 2018 Quarter, an increase of $ 36.7 million , or 25% , from the 2017 Quarter. A more detailed discussion of our segment results and other costs is included below in "Results of Operations".

    

Distribution

In October 2018 , we declared our quarterly distribution to our common unitholders of $ 0.54 per unit related to the 2018 Quarter.

With respect to our preferred units, we have declared a PIK of the quarterly distribution, which will result in the issuance of an additional approximately 523,132 preferred units. This PIK amount equates to a distribution of $0.7374 per preferred unit for the 2018 Quarter, or $2.9496 annualized. These distributions will be payable in November 2018 to unitholders holders of record at the close of business on October 31, 2018.

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Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2018 Quarter increased $259.2 million , or 53% , from the 2017 Quarter. In addition, our total costs and expenses as presented on the Unaudited Statements of Operations (excluding the gain on sale of assets) increased $259.5 million , or 59% , between those two periods. These increases are primarily attributable to the effects of three months of contribution by our Alkali Business during the 2018 Quarter compared to one month of contribution during the 2017 Quarter, along with the increase in crude oil prices during the 2018 Quarter that proportionately impact our revenues and cost of sales. Excluding the effects of our Alkali Business, operating income for the 2018 Quarter would have increased by $1.1 million compared to the 2017 Quarter.

The addition of our Alkali Business resulted in a large increase in revenues and costs relative to the 2017 Quarter (which are reflected in our sodium minerals and sulfur services segment). Those increases are principally derived from mining trona ore and processing the entrained mineral sodium carbonate, also known as naturally occurring soda ash. Natural soda ash has significant cost advantages over synthetically produced soda ash. We believe that significant cost advantage will exist for the foreseeable future. Natural soda ash accounts for only about 25% of the world's production; thus, we believe we should be able to somewhat mitigate the effects of market specific factors (e.g., changes in sales prices for our products, our operating costs, and other economic considerations) on Net Income, Available Cash before Reserves, and Segment Margin in the soda ash market in which we operate.

In addition to our Alkali Business, we continue to operate in our other legacy businesses including - (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large reservoir, long-lived crude oil and natural gas properties; and (ii) our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 80% of the volumes transported on our onshore crude pipelines, and refiners contract for over 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. The shippers on our offshore pipelines are mostly integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in relatively low commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our Net Income, Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products through our onshore facilities and transportation segment. The increase in our revenues and costs in this segment between the 2018 Quarter and the 2017 Quarter is primarily attributable to increases in crude oil and petroleum product prices and sales volumes as discussed further below. Nevertheless, generally we do not expect fluctuations in prices for crude oil and natural gas to materially affect our Net Income, Available Cash before Reserves or Segment Margin to the same extent they affect our revenues and costs. We have limited our direct commodity price exposure related to crude oil and petroleum products through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. However, due to the indirect exposure to changes in prices discussed above, the factors addressed in our onshore facilities and transportation segment discussion above, and the fact that crude oil prices have remained low for an extended period of time as compared to the five-year period before 2015, we are reasonably hopeful that we have reached a bottom in our crude oil and petroleum product sales volumes.

As discussed throughout this document and throughout our Annual Report on Form 10-K, we have some indirect exposure to certain changes in prices for crude oil and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the section of our Annual Report entitled “Risks Related to Our Business.”

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Prices of crude oil have increased since the 2017 Quarter. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") increased 44.3% to $69.55 per barrel in the 2018 Quarter, as compared to $48.21 per barrel in the 2017 Quarter. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin from those operations.

Additionally, changes in certain of our operating costs between the respective quarters, such as those associated with our sodium minerals and sulfur services, offshore pipeline and marine transportation segments, are not correlated with crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and nine months ended September 30, 2018 and September 30, 2017 was as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
Offshore pipeline transportation	70,963				78,228				$	215,738			$	243,528
Sodium minerals and sulfur services	63,942				30,031				192,875				63,864
Onshore facilities and transportation	36,189				25,606				83,622				71,999
Marine transportation	12,113				12,649				35,066				39,768
Total Segment Margin	$	183,207			$	146,514			$	527,301			$	419,159

We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. See "Non-GAAP Financial Measures" for further discussion surrounding total Segment Margin.

A reconciliation of total Segment Margin to net income for the periods presented is as follows :

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Total Segment Margin	$	183,207			$	146,514			$	527,301			$	419,159
Corporate general and administrative expenses	(23,760		)		(18,230		)		(47,686		)		(33,694		)
Depreciation, depletion, amortization and accretion	(94,522		)		(66,436		)		(252,392		)		(184,213		)
Interest expense	(58,819		)		(47,388		)		(172,864		)		(122,117		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	(7,552		)		(7,136		)		(26,646		)		(25,566		)
Other non-cash items	(999		)		(4,788		)		(7,774		)		(6,218		)
Cash payments from direct financing leases in excess of earnings	(1,931		)		(1,751		)		(5,654		)		(5,127		)
Gain on sale of assets	3,363				—				3,363				26,684
Non-cash provision for leased items no longer in use	181				—				42				(12,589		)
Differences in timing of cash receipts for certain contractual arrangements (2)	792				5,847				5,271				11,694
Loss on debt extinguishment	—				—				(3,339		)		—
Income tax expense	(283		)		(320		)		(914		)		(878		)
Net income (loss) attributable to Genesis Energy, L.P.	$	(323	)		$	6,312			$	18,708			$	67,135

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

(2) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts.

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Offshore Pipeline Transportation Segment

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues	$	60,888			$	67,506			$	181,968			$	204,585
Offshore natural gas pipeline revenue, excluding non-cash revenues	10,721				13,164				35,405				38,852
Offshore pipeline operating costs, excluding non-cash expenses	(13,828		)		(15,979		)		(44,631		)		(46,859		)
Distributions from equity investments (1)	16,781				19,535				53,870				59,100
Other	(3,599		)		(5,998		)		(10,874		)		(12,150		)
Offshore pipeline transportation Segment Margin	$	70,963			$	78,228			$	215,738			$	243,528
Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	225,186				203,697				202,159				220,374
Poseidon	224,053				257,093				229,382				258,031
Odyssey	129,777				135,787				109,897				122,433
GOPL (2)	13,217				8,317				10,707				8,166
Total crude oil offshore pipelines	592,233				604,894				552,145				609,004
Natural gas transportation volumes (MMBtus/d)	447,460				467,095				436,023				516,974
Volumetric Data net to our ownership interest (2) :
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	225,186				203,697				202,159				220,374
Poseidon	143,394				164,540				146,804				165,140
Odyssey	37,635				39,378				31,870				35,506
GOPL (3)	13,217				8,317				10,707				8,166
Total crude oil offshore pipelines	419,432				415,932				391,540				429,186
Natural gas transportation volumes (MMBtus/d)	171,080				189,778				166,252				237,328

(1)	Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2018 and 2017, respectively.

(2)	Volumes are the product of our effective ownership interest through the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.

(3)	One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system.

Three Months Ended September 30, 2018 Compared with Three Months Ended September 30, 2017

Offshore pipeline transportation Segment Margin for the 2018 Quarter decreased $7.3 million , or 9% , from the 2017 Quarter, primarily due to lower volumes on the Poseidon pipeline and certain associated laterals. We have continued to experience an inordinate amount of scheduled and unscheduled downtime at several of the production facilities connected to our offshore infrastructure. Notwithstanding these short term negatives, we are currently seeing increasing demand for our assets from production that is currently dedicated to 3rd party pipelines but is unable to get to shore due to a lack of capacity on such pipelines. Given our excess capacity and connectivity on certain of our systems, we expect to benefit from this takeaway capacity constraint in future periods.

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Nine Months Ended September 30, 2018 Compared with Nine Months Ended September 30, 2017

Offshore pipeline transportation Segment Margin for the first nine months of 2018 decreased $27.8 million , or 11% , from the first nine months of 2017, primarily due to lower volumes. We have continued to experience an inordinate amount of scheduled and unscheduled downtime at several of the production facilities connected to our offshore infrastructure. Additionally, during 2018, three particular major fields have underperformed our expectations. One field we believe is underperforming as a result of reservoir quality degradation and not due to mechanical factors. Offsetting this in future years are two subsea tie-backs to the same dedicated in-field production facility scheduled to come online; one in early 2019 and one later in 2019. The other two large underperforming fields we think are predominately timing related. To maximize reserve recoveries, the operator appears to be producing at a slower rate than communicated to us last year. Notwithstanding these short term negatives, we are currently seeing increasing demand for our assets from production that is currently dedicated to 3rd party pipelines but is unable to get to shore due to a lack of capacity on such pipelines. Given our excess capacity and connectivity on certain of our systems, we expect to benefit from this takeaway capacity constraint in future periods.

In addition, the minimum bill reservation fees we collect on one of our offshore oil pipelines had a prior year step down, and we collected approximately $4.4 million less in segment margin relative to the first nine months of 2017. Lastly, the first six months during 2017 included contributions of approximately $2.0 million from certain of our previously owned gas pipeline and platform assets that were sold during the second quarter of 2017.

Sodium Minerals and Sulfur Services Segment

Operating results for our sodium minerals and sulfur services segment were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Volumes sold:
NaHS volumes (Dry short tons "DST")	39,242				30,381				114,546				95,575
Soda Ash volumes (short tons sold)	886,253				336,000				2,739,253				336,000
NaOH (caustic soda) volumes (dry short tons sold)	29,357				21,746				87,190				55,962
Total	954,852				388,127				2,940,989				487,537
Revenues (in thousands):
NaHS revenues, excluding non-cash revenues	$	47,843			$	33,702			$	137,083			$	105,209
NaOH (caustic soda) revenues	16,731				11,145				48,709				29,511
Revenues associated with Alkali Business	203,508				65,554				615,512				65,554
Other revenues	1,894				1,355				5,328				3,963
Total external segment revenues, excluding non-cash revenues	$	269,976			$	111,756			$	806,632			$	204,237
Segment Margin (in thousands)	$	63,942			$	30,031			$	192,875			$	63,864
Average index price for NaOH per DST (1)	$	782			$	647			$	775			$	613

(1) Source: IHS Chemical.

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Three Months Ended September 30, 2018 Compared with Three Months Ended September 30, 2017

Sodium minerals and sulfur services Segment Margin for the 2018 Quarter increased $33.9 million , or 113% . This increase is primarily due to the inclusion of contributions from our Alkali Business for a full quarter during 2018 relative to one month's contribution during the 2017 Quarter. The contributions thus far from our Alkali Business have exceeded our expectations and we expect continued strong performance throughout 2018 and into 2019. Costs impacting the results of our Alkali Business, many of which are similar in nature to costs related to our sulfur removal business, include costs associated with processing and producing soda ash (and other Alkali products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). Additionally, our refinery services business continues to perform well with increased NaHS volumes of 29% during the 2018 Quarter as they benefited from increased demand from certain of our international mining customers, primarily located in South America, and our domestic mining and pulp and paper customers.

    

Nine Months Ended September 30, 2018 Compared with Nine Months Ended September 30, 2017

Sodium minerals and sulfur services Segment Margin for the first nine months of 2018 increased $129.0 million , or 202% . This increase is principally due to the inclusion of contributions from our Alkali Business for nine months during 2018 compared to one month during 2017. The contributions from our Alkali Business have exceeded our expectations and we expect continued strong performance throughout 2018 and into 2019. Costs impacting the results of our Alkali Business, many of which are similar in nature to costs related to our legacy refinery services business, include costs associated with processing and producing soda ash (and other Alkali products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). Additionally, our refinery services business continues to perform well with increased NaHS volumes of 20% during 2018 as they benefited from increased demand from certain of our international mining customers, primarily located in South America, and our domestic mining and pulp and paper customers.

Onshore Facilities and Transportation Segment

Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks, railcars, and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals, rail facilities and CO2 pipelines operating primarily within the United States Gulf Coast and Rocky Mountain crude oil markets. In addition, we utilize our railcar and trucking fleets that support the purchase and sale of gathered and bulk purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following:

•	facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to refiners via pipelines;

•	transporting CO2 from natural and anthropogenic sources to crude oil fields owned by our customers;

•	shipping crude oil and refined products to and from producers and refiners via trucks, pipelines, and railcars;

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

•	storing and blending of crude oil and intermediate and finished refined products;

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

•	purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets.

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

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in

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our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills and assets to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

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

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Operating results from our onshore facilities and transportation segment were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
Gathering, marketing, and logistics revenue	$	305,296			$	229,002			$	912,481			$	663,988
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines	20,624				17,261				55,678				48,606
Payments received under direct financing leases not included in income	1,931				1,751				5,654				5,127
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(273,286		)		(202,157		)		(833,198		)		(583,123		)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	(22,068		)		(21,199		)		(66,743		)		(64,799		)
Other	3,692				948				9,750				2,200
Segment Margin	$	36,189			$	25,606			$	83,622			$	71,999
Volumetric Data (average barrels per day):
Onshore crude oil pipelines:
Texas	33,948				45,329				28,055				28,418
Jay	13,548				13,716				14,475				14,480
Mississippi	5,603				8,104				6,520				8,478
Louisiana (1)	150,322				130,862				139,234				115,436
Wyoming	38,391				22,204				33,957				19,816
Onshore crude oil pipelines total	241,812				220,215				222,241				186,628
CO 2  pipeline (average Mcf/day):
Free State	104,628				68,363				101,764				73,042
Crude oil and petroleum products sales (average barrels per day):
Total crude oil and petroleum products sales	44,288				52,082				48,618				49,255
Rail load/unload volumes (2)	83,557				42,221				63,194				55,010

(1) Total daily volume for the three and nine months ended September 30, 2018 includes 60,896 and 57,022 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. Total daily volume for the three and nine months ended September 30, 2017 includes 66,048 and 54,974 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.

(2) Indicates total barrels for either loading or unloading at all rail facilities.

Three Months Ended September 30, 2018 Compared with Three Months Ended September 30, 2017

Onshore facilities and transportation Segment Margin for the 2018 Quarter increased $10.6 million , or 41% . This increase in the 2018 Quarter is primarily driven by increased volumes flowing through our infrastructure in the Baton Rouge corridor in Louisiana. These increased volumes are the realization of the anticipated growth within our existing commercial arrangements. Fortunately, while volumes were down on our Texas system in the 2018 Quarter relative to the 2017 Quarter due to integrity work being completed on a downstream pipeline, we were able to recognize three months of minimum volume commitments in segment margin during the 2018 Quarter. We believe the market fundamentals are intact to see increasing volumes and margin contributions both in Louisiana as well as in Texas over the next several quarters to levels sustainable for certainly the next several years.

Even after reflecting the sale of our Powder River Basin midstream assets, we would expect margin contribution from our onshore facilities and transportation segment to increase sequentially in the fourth quarter. This comes from actually moving increased volumes of crude oil rather than marketing or merchant fees which (for context) contributed less than $1 million for the third quarter.

 

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Nine Months Ended September 30, 2018 Compared with Nine Months Ended September 30, 2017

Segment Margin for our onshore facilities and transportation segment increased by $11.6 million , or 16% , between the first nine months of 2018 and the first nine months of 2017 . The first nine months of 2018 include the effects of the third quarter increase in volumes flowing through our infrastructure in the Baton Rouge corridor in Louisiana that we completed in the fourth quarter of 2016. Fortunately, while volumes were relatively constant period over period on our re-purposed Texas system (which became operational during the second quarter of 2017), we were able to recognize nine months of minimum volume commitments in segment margin during the 2018 period compared to 5 months during the 2017 period. We believe the market fundamentals are intact to see increasing volumes and margin contributions both in Louisiana as well as in Texas over the next several quarters to levels sustainable for certainly the next several years.

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 91 barges ( 82 inland and 9 offshore) with a combined transportation capacity of 3.2 million barrels, 42 push/tow boats ( 33 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:  

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
Revenues (in thousands):
Inland freight revenues	$	24,353			$	19,666			$	68,470			$	61,725
Offshore freight revenues	17,989				17,468				52,049				54,912
Other rebill revenues (1)	13,954				11,400				40,891				35,401
Total segment revenues	$	56,296			$	48,534			$	161,410			$	152,038
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	$	44,183			$	35,885			$	126,344			$	112,270
Segment Margin (in thousands)	$	12,113			$	12,649			$	35,066			$	39,768
Fleet Utilization: (2)
Inland Barge Utilization	98.6		%		90.8		%		94.7		%		90.5		%
Offshore Barge Utilization	90.9		%		99.3		%		92.5		%		98.4		%

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

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

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Three Months Ended September 30, 2018 Compared with Three Months Ended September 30, 2017

Marine transportation Segment Margin for the 2018 Quarter decreased $0.5 million , or 4% , from the 2017 Quarter. This decrease in Segment Margin is primarily attributable to our offshore barge fleet entering into short-term spot price contracts, which can lead to a less favorable rebill structure and higher operating costs, as our last legacy long term contract rolled off during the first quarter of 2018. Additionally, we had an increase in operating costs during the 2018 Quarter relative to the 2017 Quarter due to an increase in dry-docking costs. We have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market are at, or approaching, cyclical lows. These decreases were partially offset by increased segment margin in the 2018 Quarter related to the M/T American Phoenix. During the 2017 Quarter, the M/T American Phoenix underwent its planned regulatory dry-docking inspections for approximately one month which negatively impacted segment margin. The 2018 Quarter also had higher utilization on our inland barge operation during the 2018 Quarter. We are reasonably hopeful that we've reached a bottom for the quarterly segment margin from our entire fleet of assets, but we have no expectation of the fundamentals for marine transportation showing any significant improvement through at least the next several years.

Nine Months Ended September 30, 2018 Compared with Nine Months Ended September 30, 2017

Marine transportation Segment Margin for the first nine months of 2018 decreased $4.7 million , or 12% , from the first nine months of 2017 . The decrease in Segment Margin is primarily attributable to our offshore barge fleet entering into short-term spot price contracts, which can lead to a less favorable rebill structure and higher operating costs, as our last legacy term contract rolled off during the first quarter of 2018. Additionally, we had an increase in operating costs during the first nine months of 2018 relative to the first nine months of 2017 due to the increase in our dry-docking costs. We have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market are at, or approaching, cyclical lows. While we are reasonably hopeful that we've reached a bottom for the quarterly segment margin from our entire fleet of assets, we have no expectation of the fundamentals for marine transportation showing any significant improvement through at least the next several years. This excludes the M/T American Phoenix which is under long term contract through September 2020. These decreases were partially offset by increased segment margin in the 2018 period related to the M/T American Phoenix. During 2017, the M/T American Phoenix underwent its planned regulatory dry-docking inspections for approximately one month which negatively impacted segment margin. Additionally, the 2018 period also had higher utilization on our inland barge operation.

Other Costs, Interest, and Income Taxes

General and administrative expenses

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	20,624			$	7,456			$	37,910			$	24,735
Segment	482				3,233				2,198				4,809
Long-term incentive compensation expense	1,553				(1,875		)		3,171				(2,330		)
Third party costs related to business development activities and growth projects	1,550				10,595				6,133				11,509
Total general and administrative expenses	$	24,209			$	19,409			$	49,412			$	38,723

Total general and administrative expenses increased $4.8 million and $10.7 million between the three and nine month periods. This increase is primarily attributable to certain dispute costs and the effects of changes in assumptions used to value our long term incentive compensation awards during 2018. These increases were offset by lower third party transaction costs associated with our acquisition and integration of our Alkali Business during 2018 relative to 2017.

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Depreciation, depletion, and amortization expense

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
Depreciation and depletion expense	$	86,004			$	57,498			$	227,459			$	157,819
Amortization of intangible assets	5,475				5,879				16,369				17,623
Amortization of CO 2  volumetric production payments	397				355				983				1,011
Total depreciation, depletion and amortization expense	$	91,876			$	63,732			$	244,811			$	176,453

Total depreciation, depletion, and amortization expense increased $28.1 million and $68.4 million between the three and nine month periods primarily as a result of placing additional assets into service, including those acquired as a part of our Alkali Business on September 1, 2017.

Interest expense, net

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)								(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	17,259			$	13,150			$	47,700			$	37,307
Interest expense, senior unsecured notes	39,547				33,276				119,628				90,495
Amortization of debt issuance costs and discount	2,669				2,894				8,238				8,154
Capitalized interest	(656		)		(1,932		)		(2,702		)		(13,839		)
Net interest expense	$	58,819			$	47,388			$	172,864			$	122,117

Net interest expense increased $11.4 million and $50.7 million between the three and nine month periods primarily due to an increase in our average outstanding indebtedness from acquired and constructed assets, including the financing of the acquisition of our Alkali Business in 2017, along with an increase in libor rates relative to the prior period which is a major component in the interest expense derived on our senior secured credit facility. In addition, capitalized interest decreased as a result of certain of our large organic growth projects being completed and placed into service prior to September 30, 2018.

Income tax expense

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

Liquidity and Capital Resources

General

As of September 30, 2018 , we had $478.1 million of remaining borrowing capacity under our $1.7 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.

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Our primary cash requirements consist of:

•	working capital, primarily inventories and trade receivables and payables;

•	routine operating expenses;

•	capital growth and maintenance projects;

•	acquisitions of assets or businesses;

•	payments related to servicing and reducing outstanding debt; and

•	quarterly cash distributions to our unitholders.

As part of our strategic reallocation of capital, we continue to intend to allocate more capital to debt repayments and growth opportunities (and less to current distributions). 

Capital Resources

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

At September 30, 2018 , our long-term debt totaled approximately $3.7 billion , consisting of $1.2 billion outstanding under our credit facility (including $30 million borrowed under the inventory sublimit tranche) and $2.5 billion of senior unsecured notes, comprising $400 million carrying amount due on May 15, 2023 , $350 million carrying amount due on June 15, 2024 , $750 million carrying amount due August 1, 2022 , $550 million carrying amount due October 2025, and $450 million carrying amount due May 2026.

Subsequent Events

On October 11, 2018, we completed the sale of our Powder River Basin midstream assets, for which we received total net proceeds of approximately $300 million. We applied those net proceeds to reduce the balance outstanding under our revolving credit facility.    

    

Equity Distribution Program and Shelf Registration Statements

We expect to issue additional equity and debt securities in the future to assist us in meeting our future liquidity requirements, particularly those related to opportunistically acquiring assets and businesses and constructing new facilities and refinancing outstanding debt.

In 2016, we implemented an equity distribution program that will allow us to consummate “at the market” offerings of common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue additional common units from time to time, although there are limits to the amount of our “at the market” offerings the market can absorb from time to time. In connection with implementing our equity distribution program, we filed a universal shelf registration statement (our "EDP Shelf") with the SEC. Our EDP Shelf allows us to issue up to $1.0 billion of equity and debt securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in October 2020. As of September 30, 2018 , we had issued no units under this program.

We have another universal shelf registration statement (our "2018 Shelf") on file with the SEC. Our 2018 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2018 Shelf will expire in April 2021. We expect to file a replacement universal shelf registration statement before our 2018 Shelf expires.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in

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the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

In our back-to-back crude oil onshore facilities and transportation activities, we typically sell our purchased crude oil in the same month in which we acquire it, so we do not need to rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem, as we make payments and receive payments for the purchase and sale of crude oil.

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

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

    See Note 14 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, 2018 and September 30, 2017 .

Net cash flows provided by our operating activities for the nine months ended September 30, 2018 were $307.6 million compared to $206.4 million for the nine months ended September 30, 2017 . This increase in operating cash flow is primarily due to a decrease in working capital effects and an increase in overall segment margin between the nine month periods.

Capital Expenditures, Distributions and Certain Cash Requirements

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, organic growth projects, maintenance capital expenditures and distributions we pay to our unitholders. We finance maintenance capital expenditures and smaller organic growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and organic growth projects) with borrowings under our credit facility, equity issuances and/or issuances of senior unsecured notes. We currently plan to allocate a substantial portion of our excess cash flow to reduce the balance outstanding under our revolving credit facility.

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Capital Expenditures

A summary of our expenditures for fixed assets, business and other asset acquisitions for the nine months ended September 30, 2018 and September 30, 2017 is as follows :

	Nine Months Ended September 30,
	2018				2017
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets	$	2,188			$	4,093
Sodium minerals and sulfur services assets	36,109				1,616
Marine transportation assets	13,107				17,439
Onshore facilities and transportation assets	2,562				3,213
Information technology systems	64				53
Total maintenance capital expenditures	54,030				26,414
Growth capital expenditures:
Offshore pipeline transportation assets	477				4,405
Sodium minerals and sulfur services assets	12,968				5,276
Marine transportation assets	12,508				27,057
Onshore facilities and transportation assets	47,196				112,450
Information technology systems	2,747				114
Total growth capital expenditures	75,896				149,302
Total capital expenditures for fixed and intangible assets	129,926				175,716
Capital expenditures for acquisitions, inclusive of working capital acquired:
Acquisition of Alkali business	—				1,325,000
Total business combinations capital expenditures	—				1,325,000
Capital expenditures related to equity investees	2,802				—
Total capital expenditures	$	132,728			$	1,500,716

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. We continue to pursue a long-term growth strategy that may require significant capital.

Growth Capital Expenditures

We do not anticipate spending material growth capital expenditures on any individual projects during the remainder of 2018.

Maintenance Capital Expenditures

Our increase in maintenance capital expenditures for the 2018 Quarter as compared to the 2017 Quarter principally relates to our Alkali Business. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.

Distributions to Unitholders

On November 14, 2018 , we will pay a distribution of $0.54 per common unit totaling $66 million with respect to the 2018 Quarter. Information on our recent distribution history is included in Note 10 to our Unaudited Condensed Consolidated Financial Statements.

With respect to our preferred units, we have declared a PIK of the quarterly distribution, which will result in the issuance of an additional approximately 523,132 preferred units. This PIK amount equates to a distribution of $0.7374 per preferred unit for the 2018 Quarter, or $2.9496 annualized. These distributions will be payable on November 14, 2018 to unitholders holders of record at the close of business on October 31, 2018 .

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Non-GAAP Financial Measure Reconciliations

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

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

	Three Months Ended September 30,
	2018				2017
	(in thousands)
Net income (loss) attributable to Genesis Energy, L.P.	$	(323	)		$	6,312
Income Tax Expense	283				320
Depreciation, depletion, amortization and accretion	94,522				66,436
Plus (minus) Select Items, net	23,634				19,654
Maintenance capital utilized (1)	(5,200		)		(3,375		)
Cash tax expense	(234		)		(170		)
Other	1				1,860
Available Cash before Reserves	112,683				91,037

(1)	For a description of the term "maintenance capital utilized", please see the definition of the term "Available Cash before Reserves" discussed below. Maintenance capital expenditures in the 2018 Quarter and 2017 Quarter were $21.9 million and $10.9 million, respectively. This increase principally is a result of expenditures associated with our Alkali Business.

We define Available Cash before Reserves (“Available Cash before Reserves”) as net income before interest, taxes, depreciation and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, “Select Items”), as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, net interest expense and cash tax expense. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.

		Three Months Ended September 30,
		2018			2017
		(in thousands)
I.	Applicable to all Non-GAAP Measures
	Differences in timing of cash receipts for certain contractual arrangements 1	(792	)		(5,847	)
	Adjustment regarding direct financing leases 2	1,931			1,751
	Certain non-cash items:
	Unrealized loss on derivative transactions excluding fair value hedges, net of changes in inventory value	(1,989	)		2,168
	Adjustment regarding equity investees 3	7,552			7,136
	Other	2,948			3,046
	Sub-total Select Items, net 4	9,650			8,254
II.	Applicable only to Available Cash before Reserves
	Certain transaction costs 5	1,550			10,595
	Equity compensation adjustments	39			(501	)
	Other 6	12,395			1,306
	Total Select Items, net 7	23,634			19,654

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(1) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.

(2) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.

(3) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.

(4) Represents all Select Items applicable to Segment Margin and Available Cash before Reserves

(5) Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in advance of acquisition.

(6) Includes general and administrative costs associated with certain dispute costs.

(7) Represents Select Items applicable to Available Cash before Reserves.

Non-GAAP Financial Measures

General

    

To help evaluate our business, we use the non-generally accepted accounting principle (“non-GAAP”) financial measure of Available Cash before Reserves. We also present total Segment Margin as if it were a non-GAAP measure. Our Non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The schedules above provide reconciliations of Available Cash before Reserves to its most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States of America (GAAP). A reconciliation of total Segment Margin to net income is also included in our segment disclosure in Note 12 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just two of the relevant data points considered from time to time.

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

In the fourth quarter of 2017, we revised portions of the format and definitions relating to our presentation of non-GAAP financial measures. Amounts attributable to prior periods have been recast.

Segment Margin

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. We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results.

A reconciliation of total Segment Margin to net income is included in our segment disclosure in Note 12 to our Unaudited Condensed Consolidated Financial Statements, as well as previously in this Item 2.

Available Cash before Reserves

Purposes, Uses and Definition

Available Cash before Reserves, often referred to by others as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:

(1)	the financial performance of our assets;

(2)	our operating performance;

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

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

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

Disclosure Format Relating to Maintenance Capital

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

Maintenance Capital Requirements

Maintenance Capital Expenditures

Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.

Initially, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

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

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

Maintenance Capital Utilized

We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as

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that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.

Because we did not initially use our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

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, 2017 .

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, 2017 , 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, estimated or projected future financial performance, and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:

•	demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, soda ash, caustic soda and CO 2 , 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 infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

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

•	shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants, or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell soda ash, petroleum, or other 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, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;

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

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

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

•	loss of key personnel;

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

•	an increase in the competition that our operations encounter;

•	cost and availability of insurance;

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

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

•	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, 2017 . These risks may also be specifically described in our Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2017 . There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 15 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures

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

There were no changes during the third quarter of 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2017 . There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

There has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 .

For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017 , as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

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

There were no sales of unregistered equity securities during the 2018 Quarter.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Information regarding mine safety and other regulatory action at our mines in Green River and Granger, Wyoming is including in Exhibit 95 to this Form 10-Q.

Item 5. Other Information

None.

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 of the 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 the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).
	3.3		Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 5.1 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4		First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated September 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 7, 2017, File No. 001-12295).
	3.5		Second Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated December 31, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated January 4, 2018, File No. 001-12295).
	3.6		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 the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295)
	3.7		Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).

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	3.8		Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 5.2 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.9		Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006 (incorporated by reference to Exhibit 3.7 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	3.10		Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	4.1		Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
*	4.2		Fourteenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of August 28, 2018, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.3		Twelfth Supplemental Indenture for 6.000% Senior Notes due 2023, 6.75% Senior Notes due 2022, 6.50% Senior Notes due 2025, and 6.250% Senior Notes due 2026, dated as of August 28, 2018, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
	10.1		Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 28, 2018, among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders and other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 31, 2018, File No. 333-177012).
*	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.
*	95		Mine Safety Disclosures
*	101.INS		XBRL Instance Document
*	101.SCH		XBRL Schema Document
*	101.CAL		XBRL Calculation Linkbase Document
*	101.LAB		XBRL Label Linkbase Document
*	101.PRE		XBRL Presentation Linkbase Document
*	101.DEF		XBRL Definition Linkbase Document

*	Filed herewith

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SIGNATURES

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

		GENESIS ENERGY, L.P. (A Delaware Limited Partnership)
	By:	GENESIS ENERGY, LLC, as General Partner

 

Date:	November 1, 2018	By:	/s/ R OBERT  V. D EERE
			Robert V. Deere
			Chief Financial Officer
			(Duly Authorized Officer)

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