Genesis Energy (GEL) 10-K 27 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 27, 2020	Jun. 30, 2019
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Title of 12(b) Security	Common Units
Entity Address, Address Line One	919 Milam, Suite 2100,
Entity Incorporation, State or Country Code	DE
Document Annual Report	true
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	GENESIS ENERGY LP
Entity Central Index Key	0001022321
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2.3
Document Transition Report	false
Entity File Number	1-12295
Entity Tax Identification Number	76-0513049
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	860-2500
Trading Symbol	GEL
Security Exchange Name	NYSE
Common Class A
Entity Common Stock, Shares Outstanding		122,539,221
Common Class B
Entity Common Stock, Shares Outstanding		39,997

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents		$ 29,128	$ 10,300
Restricted cash		27,277	0
Accounts receivable—trade, net		417,002	323,462
Inventories		65,137	73,531
Other		54,530	35,986
Total current assets		593,074	443,279
FIXED ASSETS, at cost		5,540,596	5,440,858
Less: Accumulated depreciation		(1,246,121)	(1,023,825)
Net fixed assets		4,294,475	4,417,033
MINERALS LEASEHOLDS, net of accumulated depletion		555,825	560,481
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income		107,702	116,925
EQUITY INVESTEES		334,523	355,085
INTANGIBLE ASSETS, net of amortization		138,927	162,602
GOODWILL		301,959	301,959
RIGHT OF USE ASSETS, net		177,071	0
OTHER ASSETS, net of amortization		94,085	121,707
TOTAL ASSETS		6,597,641	6,479,071
CURRENT LIABILITIES:
Accounts payable—trade		218,737	127,327
Accrued liabilities		196,758	205,507
Total current liabilities		415,495	332,834
SENIOR SECURED CREDIT FACILITY		959,300	970,100
SENIOR UNSECURED NOTES, net of debt issuance costs		2,469,937	2,462,363
DEFERRED TAX LIABILITIES		12,640	12,576
OTHER LONG-TERM LIABILITIES		393,850	259,198
Total liabilities		4,251,222	4,037,071
MEZZANINE CAPITAL
Class A Convertible Preferred Units, 25,336,778 and 24,438,022 issued and outstanding at December 31, 2019 and 2018, respectively		790,115	761,466
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		125,133	0
COMMITMENTS AND CONTINGENCIES (Note 22)
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 122,579,218 units issued and outstanding at December 31, 2019 and 2018, respectively		1,443,320	1,690,799
Accumulated other comprehensive income (loss)	[1]	(8,431)	939
Noncontrolling interests		(3,718)	(11,204)
Total partners' capital		1,431,171	1,680,534
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		$ 6,597,641	$ 6,479,071
[1]	The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Common units issued (in units)	122,579,218	122,579,218
Common units outstanding (in units)	122,579,218	122,579,218
Class A Convertible Preferred Units
Convertible preferred units issued (in units)	25,336,778	24,438,022
Convertible preferred units outstanding (in units)	25,336,778	24,438,022
Redeemable Non Controlling Interest
Convertible preferred units issued (in units)	130,000,000	0
Convertible preferred units outstanding (in units)	130,000,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES:
Total revenues	$ 2,480,820	$ 2,912,770	$ 2,028,377
COSTS AND EXPENSES:
General and administrative	52,687	66,898	66,421
Depreciation, depletion and amortization	319,806	313,190	252,480
Impairment expense	0	126,282	0
Gain on sale of assets	0	(42,264)	(40,311)
Total costs and expenses	2,208,117	2,742,522	1,807,826
OPERATING INCOME	272,703	170,248	220,551
Equity in earnings of equity investees	56,484	43,626	51,046
Interest expense	(219,440)	(229,191)	(176,762)
Other income (expense)	(9,026)	5,023	(16,715)
Income (loss) from operations before income taxes	100,721	(10,294)	78,120
Income tax benefit (expense)	(655)	(1,498)	3,959
NET INCOME (LOSS)	100,066	(11,792)	82,079
Net loss (income) attributable to noncontrolling interests	(1,834)	5,717	568
Net income attributable to redeemable noncontrolling interests	(2,233)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	95,999	(6,075)	82,647
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(74,467)	(69,801)	(21,995)
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS	$ 21,532	$ (75,876)	$ 60,652
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON UNIT:
Basic and Diluted (in dollars per unit)	$ 0.18	$ (0.62)	$ 0.50
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted (in units)	122,579	122,579	121,546
Offshore pipeline transportation
REVENUES:
Total revenues	$ 318,116	$ 284,544	$ 318,239
COSTS AND EXPENSES:
Cost of products and services sold	58,996	66,668	72,065
Sodium minerals and sulfur services
REVENUES:
Total revenues	1,105,987	1,174,434	462,622
COSTS AND EXPENSES:
Cost of products and services sold	883,692	912,491	333,918
Marine transportation
REVENUES:
Total revenues	235,645	219,937	205,287
COSTS AND EXPENSES:
Cost of products and services sold	178,032	172,527	154,606
Onshore facilities and transportation
REVENUES:
Total revenues	821,072	1,233,855	1,042,229
COSTS AND EXPENSES:
Cost of products and services sold	714,904	1,126,730	968,647
Onshore facilities and transportation | Onshore facilities and transportation product costs
COSTS AND EXPENSES:
Cost of products and services sold	637,699	1,037,688	866,458
Onshore facilities and transportation | Onshore facilities and transportation operating costs
COSTS AND EXPENSES:
Cost of products and services sold	$ 77,205	$ 89,042	$ 102,189

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 100,066	$ (11,792)	$ 82,079
Other comprehensive income (loss):
Decrease (increase) in benefit plan liability	(9,370)	1,543	(604)
Total Comprehensive income (loss)	86,629	(4,532)	82,043
Comprehensive (income) loss attributable to noncontrolling interests	(1,834)	5,717	568
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Redeemable Noncontrolling interest	(2,233)	0	0
Comprehensive income (loss) attributable to Genesis Energy, L.P.	$ 90,696	$ (10,249)	$ 81,475

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands		Total	Previously Reported	Restatement Adjustment	Partners' Capital	Partners' CapitalPreviously Reported	Partners' CapitalRestatement Adjustment	Partners' CapitalNumber of Common Units	Partners' CapitalNumber of Common UnitsPreviously Reported	Noncontrolling Interest	Noncontrolling InterestPreviously Reported	Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive LossPreviously Reported
Partners' capital, beginning balance (in units) at Dec. 31, 2016								117,979,000
Partners' capital, beginning balance at Dec. 31, 2016		$ 2,120,050			$ 2,130,331					$ (10,281)		$ 0
PARTNERS’ CAPITAL:
Net income (loss)		82,079			82,647					(568)
Cash distributions to partners, net		(321,875)			(321,875)
Cash contributions from noncontrolling interests		2,770								2,770
Issuance of common units for cash, net (in units)								4,600,000
Issuance of common units for cash, net		140,513			140,513
Other comprehensive income (loss)		(604)										(604)
Distributions to preferred unitholders		(5,469)			(5,469)
Partners' capital, ending balance (in units) at Dec. 31, 2017								122,579,000	122,579,000
Partners' capital, ending balance at Dec. 31, 2017		2,013,914	$ 2,017,464		2,022,597	$ 2,026,147				(8,079)	$ (8,079)	(604)	$ (604)
Partners' capital, ending balance (ASC 606) at Dec. 31, 2017				$ (3,550)			$ (3,550)
PARTNERS’ CAPITAL:
Net income (loss)		(11,792)			(6,075)					(5,717)
Cash distributions to partners, net		(257,416)			(257,416)
Cash contributions from noncontrolling interests		2,592								2,592
Other comprehensive income (loss)		1,543										1,543
Distributions to preferred unitholders		$ (68,307)			(68,307)
Partners' capital, ending balance (in units) at Dec. 31, 2018		122,579,218						122,579,000
Partners' capital, ending balance at Dec. 31, 2018		$ 1,680,534			1,690,799					(11,204)		939
PARTNERS’ CAPITAL:
Net income (loss)	[1]	97,833			95,999					1,834
Cash distributions to partners, net		(269,674)			(269,674)
Cash contributions from noncontrolling interests		5,652								5,652
Other comprehensive income (loss)		(9,370)										(9,370)
Distributions to preferred unitholders		$ (73,804)			(73,804)
Partners' capital, ending balance (in units) at Dec. 31, 2019		122,579,218						122,579,000
Partners' capital, ending balance at Dec. 31, 2019		$ 1,431,171			$ 1,443,320					$ (3,718)		$ (8,431)
PARTNERS’ CAPITAL:
Accumulated distributions to preferred unitholders		$ (74,500)
[1]	Net income includes $74.5 million attributable to our Class A Convertible preferred unitholders accumulated as of December 31, 2019 .

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 100,066	$ (11,792)	$ 82,079
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	319,806	313,190	252,480
Provision for leased items no longer in use	0	0	12,589
Gain on sale of assets	0	(42,264)	(40,311)
Impairment expense	0	126,282	0
Amortization and write-off of debt issuance costs and premium or discount	10,766	12,165	13,103
Amortization of unearned income and initial direct costs on direct financing leases	(12,247)	(13,035)	(13,747)
Payments received under direct financing leases	20,668	20,668	20,668
Equity in earnings of investments in equity investees	(56,484)	(43,626)	(51,046)
Cash distributions of earnings of equity investees	56,081	42,735	47,316
Non-cash effect of long-term incentive compensation plans	8,496	3,941	(5,775)
Deferred and other tax benefits	65	663	(4,060)
Unrealized (gains) losses on derivative transactions	12,586	(11,795)	10,943
Other, net	(6,418)	(4,941)	(10,839)
Net changes in components of operating assets and liabilities, net of acquisitions (See Note 16)	(71,098)	(2,152)	10,156
Net cash provided by operating activities	382,287	390,039	323,556
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(163,248)	(195,367)	(250,593)
Cash distributions received from equity investees—return of investment	21,250	28,979	35,582
Investments in equity investees	0	(3,018)	(4,647)
Acquisitions	0	0	(1,325,759)
Contributions in aid of construction costs	0	0	124
Proceeds from asset sales	1,187	310,099	85,722
Net cash used in (provided by) investing activities	(140,811)	140,693	(1,459,571)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	815,100	980,700	1,458,700
Repayments on senior secured credit facility	(825,900)	(1,109,800)	(1,637,700)
Proceeds from issuance of senior unsecured notes	0	0	1,000,000
Net proceeds from issuance of preferred units (Note 12)	122,900	0	726,419
Repayment of senior unsecured notes	0	(145,170)	(204,830)
Debt issuance costs	0	(242)	(25,913)
Issuance of common units for cash, net	0	0	140,513
Contributions from noncontrolling interests	5,652	2,592	2,770
Distributions to Class A Convertible Preferred unitholders	(43,506)	0	0
Distributions to common unitholders	(269,674)	(257,416)	(321,875)
Other, net	57	(137)	(57)
Net cash provided by (used in) financing activities	(195,371)	(529,473)	1,138,027
Net increase in cash and cash equivalents and restricted cash	46,105	1,259	2,012
Cash and cash equivalents and restricted cash at beginning of period	10,300	9,041	7,029
Cash and cash equivalents and restricted cash at end of period	$ 56,405	$ 10,300	$ 9,041

Organization

Organization	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization We are a growth-oriented master limited partnership founded 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 in the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprise and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing, producing, marketing, and selling business based on Wyoming (our "Alkali Business"), refinery-related plants, storage tanks and terminals, railcars, rail 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. We currently manage our businesses through four divisions that constitute our reportable segments: • Offshore pipeline transportation, which includes 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, soda ash production, 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 terminaling, 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

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Consolidation and Presentation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2019 , 2018 and 2017 . All intercompany balances and transactions have been eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries. 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. Joint Ventures We participate in several joint ventures, including, in our offshore pipeline transportation segment, a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29% interest in Odyssey Pipeline L.L.C. (or "Odyssey"). We account for our investments in these joint ventures by the equity method of accounting. See Note 9 . Use of Estimates The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. Restricted Cash Our restricted cash balance represents cash held to be used for purposes of our Granger expansion project, as well as a minimum working capital balance we are required to maintain at our unrestricted subsidiary level under contractual agreement and is classified as current on our Consolidated Balance Sheets ( Note 12 ). Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. Inventories Our inventories are valued at the lower of cost and net realizable value. With the exception of our Alkali Business, cost is determined principally under the average cost method within specific inventory pools. Within our Alkali Business, the cost of inventories are determined using the FIFO, except for materials and supplies which are recorded at average cost, and raw materials which are recorded at standard cost, which approximates actual cost. Fixed Assets and Mineral Leaseholds Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 40 years for pipelines and related assets, 20 to 30 years for marine vessels, 3 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 20 years for buildings and improvements, office equipment, furniture and fixtures and other equipment. Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost. Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, the costs incurred to develop such property through the commencement of production are capitalized. Deferred Charges on Marine Transportation Assets Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last. Asset Retirement Obligations Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO 2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. An ongoing expense is recognized for changes in fair value of the liability as a result of the passage of time, which is recorded as accretion expense and included within offshore pipeline transportation operating costs in the Consolidated Statements of Operations. See Note 8 . Lease Accounting We enter into operating lease contracts for the right to utilize certain transportation equipment, facilities and equipment, and office space from third parties. For contracts that extend for a period greater than 12 months, we recognize a right of use asset and a corresponding lease liability on our Consolidated Balance Sheet. The present value of each lease is based on the future minimum lease payments in accordance with ASC 842 and is determined by discounting these payments using an incremental borrowing rate. From time to time, we enter into agreements in which we are lessors of our property or equipment. For operating leases, revenue is recorded once payment is received. For our direct finance lease we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in onshore facilities and transportation revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets. Refer to Note 4 for additional information. Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight line basis. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with our credit facilities and their related amendments have historically been capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Certain of our capitalized debt issuance costs related to our respective issuances of notes are classified as reductions in long-term debt. Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. We may also elect to exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. If the calculated fair value of the reporting unit exceeds its carrying value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, the goodwill of that reporting unit is considered to be impaired and a charge to earnings must be recorded. The impact to earnings is the excess amount of carrying value over fair value, however the charge is not to exceed the total amount of goodwill allocated to the reporting unit under evaluation. See Note 10 for further information. Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred. Equity-Based Compensation Our phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the market price of our common units. Our phantom units include both service-based and performance-based awards. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. See Note 17 for more information. Revenue Recognition We recognize revenue across our operating segments upon the satisfaction of their respective performance obligations. Refer to Note 3 for additional details on what constitutes a performance obligation in each of our businesses. Cost of Sales and Operating Expenses Onshore facilities and transportation operating and product costs include the cost to acquire the product and the associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and other vessels, including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein. When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as onshore facilities and transportation revenues. Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often rebillable and passed through to the customer. The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda. Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines. Income Taxes We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner. Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations. Derivative Instruments and Hedging Activities When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. In addition, we have determined that certain provisions in our Class A Convertible Preferred units represent an embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods being recorded in our Consolidated Statements of Operations. See Note 19 for further information on these items. Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature. Pension benefits We sponsor a defined benefit plan for employees of our Alkali Business. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income (loss). Business Acquisitions For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. See Note 5 for more information regarding our acquisition accounting and recording of acquisition costs. Recent and Proposed Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. The standard requires varying transition methods for the different categories of amendments. We have performed an assessment which consisted of reviewing current and historical information pertaining to our trade accounts receivable and existing contract assets and we anticipate no material impact to our consolidated financial statements as of the adoption date. 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. Refer to Note 3 for further details. We have adopted guidance under ASC Topic 842, Lease Accounting ("ASC 842"), as of January 1, 2019 utilizing the modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to easements, separation of lease components, and the package of practical expedients, which among other things, allows us to carry over previous lease conclusions reached under ASC 840. As a result of adopting the new lease standard, we recorded an operating lease right of use asset of approximately $209 million with a corresponding lease liability as of the transition date. Refer to Note 4 for further details. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance 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 $15.3 million from operating cash flows to investing cash flows for the year ended December 31, 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 year ended December 31, 2018. In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We elected to early adopt this standard as of January 1, 2017. See Note 10

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue Recognition [Abstract]
Revenue Recognition	Revenue Recognition Revenue from Contracts with Customers The following table reflects the disaggregation of our revenues by major category for the years ended December 31, 2019 and December 31, 2018, respectively: Year Ended December 31, 2019 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated Fee-based revenues $ 160,431 $ — $ 318,116 $ 235,645 $ 714,192 Product Sales 660,641 1,023,667 — — 1,684,308 Refinery Services — 82,320 — — 82,320 $ 821,072 $ 1,105,987 $ 318,116 $ 235,645 $ 2,480,820 Year Ended December 31, 2018 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated Fee-based revenues $ 156,266 $ — $ 284,544 $ 219,937 $ 660,747 Product Sales 1,077,589 1,071,634 — — 2,149,223 Refinery Services — 102,800 — — 102,800 $ 1,233,855 $ 1,174,434 $ 284,544 $ 219,937 $ 2,912,770 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 simultaneously 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. Certain of our contracts include a single performance obligation to stand ready, on a 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 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, our performance obligation 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 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. The consideration we receive 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 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 allow for us to make volumetric deductions 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 in the transaction price on a net basis. The net oil recorded is valued at the lower of cost or net realizable value using the market price of crude oil during the month the product was transported. 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 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. Our performance obligation consists of 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 the 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 treating 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 at a 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 that we 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). Contract Assets and Liabilities The table below depicts our contract asset and liability balances at December 31, 2019 and December 31, 2018: Contract Assets Contract Assets Contract Liabilities Contract Liabilities Current Non-Current Current Non-Current Balance at December 31, 2018 $ — $ 72,241 $ — $ 26,271 Balance at December 31, 2019 21,912 54,232 2,896 23,170 During the year ended December 31, 2019, $2.0 million that was previously classified as a contract liability at the beginning of the period was recognized as revenue. No such revenues were recognized for the year ended December 31, 2018. Additionally, no revenues were recognized related to performance obligations satisfied or partially satisfied from a previous period for the years ended December 31, 2019 and December 31, 2018 and we did not have any contract modifications during the period that would affect our contract asset and liability balances. Accounts receivable-trade, net does not include consideration received in kind from our refinery services process. 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 December 31, 2019. However, ASC 606 provides 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. 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 Onshore Facilities and Transportation 2020 $ 75,021 $ 57,615 2021 58,623 20,269 2022 69,134 4,283 2023 58,540 — 2024 52,812 — Thereafter 154,899 — Total $ 469,029 $ 82,167

Lease Accounting

Lease Accounting	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease Accounting	Lease Accounting Lessee Arrangements We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of less than 12 months are not recorded on our consolidated balance sheet and we recognize lease expense for these leases on a straight line basis over the lease term. Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally, certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as incurred and are not included in our determination for our lease liability and right of use asset. As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our incremental borrowing rate based on the information available at January 1, 2019 in determining the present value of lease payments. Our lease portfolio consists of operating leases within three major categories: Leases Classification Financial Statement Caption December 31, January 1, Assets Transportation Equipment Right of Use Assets, net $ 98,588 $ 117,727 Office Space & Equipment Right of Use Assets, net 11,085 14,194 Facilities and Equipment Right of Use Assets, net 67,398 77,008 Total Right of Use Assets, net $ 177,071 $ 208,929 Liabilities Current Accrued liabilities 28,406 33,016 Non-Current Other long-term liabilities 144,910 171,348 Total Lease Liability $ 173,316 $ 204,364 Our Right of Use Assets, net balance above includes our unamortized initial direct costs associated with certain of our transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease ( Note 10 ). Our lease liability includes our remaining provision for each period presented for our cease-use provision for railcars no longer in use. We recorded total operating lease expense of $27.2 million , $30.8 million , and $36.9 million for the years ended December 31, 2019 , 2018, and 2017. The total operating lease expense is net of our variable railcar mileage credits we receive in our Alkali Business of $24.8 million , $26.2 million , and $8.4 million for the years ended December 31, 2019, 2018, and 2017, for which we only owned our Alkali Business for four months. The total operating cost includes the amounts associated with our existing lease liabilities, along with both short term and variable lease costs incurred during the period which are not significant to the operating lease cost individually, or in the aggregate. The maturities of our operating lease liabilities as of December 31, 2019 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheet: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2020 $ 26,355 $ 4,119 $ 9,309 $ 39,783 2021 20,282 3,163 6,696 30,141 2022 18,022 2,453 5,383 25,858 2023 17,160 678 5,325 23,163 2024 16,355 689 4,801 21,845 Thereafter 27,163 1,723 123,897 152,783 Total Lease Payments 125,337 12,825 155,411 293,573 Less: Interest (23,428 ) (1,619 ) (95,210 ) (120,257 ) Present value of operating lease liabilities $ 101,909 $ 11,206 $ 60,201 $ 173,316 The following table presents the weighted average remaining term and discount rate related to our right of use assets: Lease Term and Discount Rate December 31, Weighted-average remaining lease term 12.53 years Weighted-average discount rate 7.61% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Cash Flows Information December 31, Cash paid for amounts included in the measurement of lease liabilities $ 44,046 Leased assets obtained in exchange for new operating lease liabilities 198,389 Lessor Arrangements We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties. Operating Leases We act as a lessor in our revenue contract associated with the M/T American Phoenix, within our marine transportation segment. The M/T American Phoenix ocean tanker is currently under charter along the Gulf Coast with a large refining customer. We recorded lease revenue of $27.0 million for the year ended December 31, 2019 , $27.0 million for the year ended December 31, 2018 and $25.1 million for the year ended December 31, 2017, respectively, which is recorded in marine transportation revenues on the Consolidated Statements of Operations. Additionally, we act as a lessor on our Free State pipeline system, which is included in the onshore and facilities transportation segment. The Free State pipeline is an 86 mile pipeline in Eastern Mississippi used to transport CO 2 that is recovered in the area downstream to several delivery points in and around the Mississippi region. Our Free State pipeline is currently under lease through 2028 to an affiliate of an independent crude oil company. We receive fixed installments through the life of the lease as well as variable consideration that is determined by average daily volumes of throughput. We recorded total revenue of $6.1 million for the year ended December 31, 2019 , $6.6 million for the year ended December 31, 2018 and $5.2 million for the year ended December 31, 2017, respectively, which is recorded in onshore facilities and transportation revenues on the Consolidated Statements of Operations. Direct Finance Lease Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008 . These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25% . At the end of the lease term in 2028 , we will convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment. The following table details the fixed lease payments we will receive for our lessor arrangements as of December 31, 2019 : Operating Leases Direct Financing Lease Maturity of Lessor Receipts Marine Transportation Onshore Facilities and Transportation Onshore Facilities and Transportation 2020 $ 20,128 $ 1,200 $ 20,668 2021 — 1,200 20,668 2022 — 1,200 20,668 2023 — 1,200 20,668 2024 — 1,200 20,668 Thereafter — 4,100 72,336 Total Lease Receipts 20,128 10,100 175,676 Less: Interest — — (58,680 ) Total Net Lease Receipts $ 20,128 $ 10,100 $ 116,996 The present value of our lease receivables for our direct finance lease includes a current portion of $9.3 million and $8.4 million , which is recorded in other current assets on the Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 , respectively.
Lease Accounting	Lease Accounting Lessee Arrangements We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of less than 12 months are not recorded on our consolidated balance sheet and we recognize lease expense for these leases on a straight line basis over the lease term. Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally, certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as incurred and are not included in our determination for our lease liability and right of use asset. As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our incremental borrowing rate based on the information available at January 1, 2019 in determining the present value of lease payments. Our lease portfolio consists of operating leases within three major categories: Leases Classification Financial Statement Caption December 31, January 1, Assets Transportation Equipment Right of Use Assets, net $ 98,588 $ 117,727 Office Space & Equipment Right of Use Assets, net 11,085 14,194 Facilities and Equipment Right of Use Assets, net 67,398 77,008 Total Right of Use Assets, net $ 177,071 $ 208,929 Liabilities Current Accrued liabilities 28,406 33,016 Non-Current Other long-term liabilities 144,910 171,348 Total Lease Liability $ 173,316 $ 204,364 Our Right of Use Assets, net balance above includes our unamortized initial direct costs associated with certain of our transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease ( Note 10 ). Our lease liability includes our remaining provision for each period presented for our cease-use provision for railcars no longer in use. We recorded total operating lease expense of $27.2 million , $30.8 million , and $36.9 million for the years ended December 31, 2019 , 2018, and 2017. The total operating lease expense is net of our variable railcar mileage credits we receive in our Alkali Business of $24.8 million , $26.2 million , and $8.4 million for the years ended December 31, 2019, 2018, and 2017, for which we only owned our Alkali Business for four months. The total operating cost includes the amounts associated with our existing lease liabilities, along with both short term and variable lease costs incurred during the period which are not significant to the operating lease cost individually, or in the aggregate. The maturities of our operating lease liabilities as of December 31, 2019 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheet: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2020 $ 26,355 $ 4,119 $ 9,309 $ 39,783 2021 20,282 3,163 6,696 30,141 2022 18,022 2,453 5,383 25,858 2023 17,160 678 5,325 23,163 2024 16,355 689 4,801 21,845 Thereafter 27,163 1,723 123,897 152,783 Total Lease Payments 125,337 12,825 155,411 293,573 Less: Interest (23,428 ) (1,619 ) (95,210 ) (120,257 ) Present value of operating lease liabilities $ 101,909 $ 11,206 $ 60,201 $ 173,316 The following table presents the weighted average remaining term and discount rate related to our right of use assets: Lease Term and Discount Rate December 31, Weighted-average remaining lease term 12.53 years Weighted-average discount rate 7.61% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Cash Flows Information December 31, Cash paid for amounts included in the measurement of lease liabilities $ 44,046 Leased assets obtained in exchange for new operating lease liabilities 198,389 Lessor Arrangements We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties. Operating Leases We act as a lessor in our revenue contract associated with the M/T American Phoenix, within our marine transportation segment. The M/T American Phoenix ocean tanker is currently under charter along the Gulf Coast with a large refining customer. We recorded lease revenue of $27.0 million for the year ended December 31, 2019 , $27.0 million for the year ended December 31, 2018 and $25.1 million for the year ended December 31, 2017, respectively, which is recorded in marine transportation revenues on the Consolidated Statements of Operations. Additionally, we act as a lessor on our Free State pipeline system, which is included in the onshore and facilities transportation segment. The Free State pipeline is an 86 mile pipeline in Eastern Mississippi used to transport CO 2 that is recovered in the area downstream to several delivery points in and around the Mississippi region. Our Free State pipeline is currently under lease through 2028 to an affiliate of an independent crude oil company. We receive fixed installments through the life of the lease as well as variable consideration that is determined by average daily volumes of throughput. We recorded total revenue of $6.1 million for the year ended December 31, 2019 , $6.6 million for the year ended December 31, 2018 and $5.2 million for the year ended December 31, 2017, respectively, which is recorded in onshore facilities and transportation revenues on the Consolidated Statements of Operations. Direct Finance Lease Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008 . These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25% . At the end of the lease term in 2028 , we will convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment. The following table details the fixed lease payments we will receive for our lessor arrangements as of December 31, 2019 : Operating Leases Direct Financing Lease Maturity of Lessor Receipts Marine Transportation Onshore Facilities and Transportation Onshore Facilities and Transportation 2020 $ 20,128 $ 1,200 $ 20,668 2021 — 1,200 20,668 2022 — 1,200 20,668 2023 — 1,200 20,668 2024 — 1,200 20,668 Thereafter — 4,100 72,336 Total Lease Receipts 20,128 10,100 175,676 Less: Interest — — (58,680 ) Total Net Lease Receipts $ 20,128 $ 10,100 $ 116,996 The present value of our lease receivables for our direct finance lease includes a current portion of $9.3 million and $8.4 million , which is recorded in other current assets on the Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 , respectively.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions	Acquisitions 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 mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na 2 CO 3 ), as 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 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017, generating net proceeds of $726.4 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 and the 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 the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2017. The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Accounts receivable $ 138,258 Inventories 34,929 Other current assets 13,254 Fixed assets 663,217 Mineral leaseholds 566,019 Intangible assets 800 Other assets 3,612 Accounts payable (44,547 ) Accrued Liabilities (36,884 ) Other long-term liabilities (13,658 ) Total Purchase Price $ 1,325,000 Fixed assets identified in connection with our valuation and purchase price allocation include the related facilities, machinery and equipment associated with our Alkali Business, principally at our Green River, Wyoming operations. These assets will be depreciated under the straight line method and have useful lives ranging from 2 to 30 years. Mineral leaseholds include the trona reserves at our Green River, Wyoming facility and are depleted over their useful lives as determined by the units of production method. Other long-term liabilities contains various items including assumed employee benefit plan obligations. Other items principally consist of working capital items of our Alkali Business as acquired on September 1, 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: Year Ended December 31 2017 Revenues $ 277,011 Net income 42,014 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, 2016 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 our 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 preferred units and interest expense on incremental borrowings. The dilutive effect of our Class A Convertible Preferred Units is calculated using the if-converted method. Year Ended December 31 2017 Pro forma consolidated financial operating results: Revenues $ 2,549,438 Net Income Attributable to Genesis Energy, L.P. 108,392 Net Income Available to Common Unitholders 42,768 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 Pro forma net income per common unit, basic and dilutive $ 0.35 As relating to our Alkali Business acquisition, we incurred approximately $12.0 million in acquisition related costs through December 31, 2017, and incurred an additional $2.0 million during the year ended December 31, 2018. Such costs are included as "General and Administrative costs" on our Consolidated Statement of Operations.

Receivables

Receivables	12 Months Ended
	Dec. 31, 2019
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Receivables	Receivables Accounts receivable – trade, net consisted of the following: December 31, 2019 2018 Accounts receivable - trade $ 418,064 $ 330,855 Allowance for doubtful accounts (1,062 ) (7,393 ) Accounts receivable - trade, net $ 417,002 $ 323,462 The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2019 2018 2017 Balance at beginning of period $ 7,393 $ 8,468 $ 6,505 Charged to costs and expenses, net of recoveries (5,572 ) 31 2,001 Amounts written off (759 ) (1,106 ) (38 ) Balance at end of period $ 1,062 $ 7,393 $ 8,468

Inventories

Inventories	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventories	Inventories The major components of inventories were as follows: December 31, 2019 2018 Petroleum products $ 2,721 $ 12,203 Crude oil 5,271 8,379 Caustic soda 5,965 10,372 NaHS 10,845 12,400 Raw materials - Alkali Operations 6,238 5,952 Work-in-process - Alkali Operations 8,579 2,322 Finished goods, net - Alkali Operations 14,168 11,402 Materials and supplies, net - Alkali Operations 11,350 10,490 Other — 11 Total $ 65,137 $ 73,531 Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were no t recorded below cost as of December 31, 2019 and were recorded below cost by $1.0 million as of December 31, 2018 ; therefore we reduced the value of inventory in our Consolidated Financial Statements for this difference in 2018.

Fixed Assets and Asset Retireme

Fixed Assets and Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Fixed Assets And Asset Retirement Obligations [Abstract]
Fixed Assets and Asset Retirement Obligations	Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations Fixed Assets Fixed assets consisted of the following: December 31, 2019 2018 Crude oil pipelines and natural gas pipelines and related assets $ 2,891,489 $ 2,918,285 Alkali facilities, machinery, and equipment 591,547 533,924 Onshore facilities, machinery, and equipment 640,376 639,023 Transportation equipment 19,864 20,102 Marine vessels 979,171 951,597 Land, buildings and improvements 238,451 222,242 Office equipment, furniture and fixtures 22,645 20,505 Construction in progress 115,162 94,025 Other 41,891 41,155 Fixed assets, at cost 5,540,596 5,440,858 Less: Accumulated depreciation (1,246,121 ) (1,023,825 ) Net fixed assets $ 4,294,475 $ 4,417,033 Mineral Leaseholds Our Mineral Leaseholds, relating to our acquired Alkali Business, consist of the following: December 31, December 31, Mineral leaseholds $ 566,019 $ 566,019 Less: Accumulated depletion (10,194 ) (5,538 ) Mineral leaseholds, net $ 555,825 $ 560,481 Depreciation expense was $295.6 million , $286.0 million and $226.0 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Depletion expense was $4.7 million , $4.0 million , and $1.5 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. On October 11, 2018, we completed the divestiture of our Powder River Basin midstream assets, included in our Onshore Facilities and Transportation segment, and received total net proceeds of approximately $300 million . This sale resulted in a gain of $38.9 million recorded in Gains on assets sales in the Consolidated Statements of Operations. Additionally, we recorded an impairment expense of $21.2 million on our remaining non-core midstream assets in the Powder River Basin as the carrying value exceeded the fair value in the current market at December 31, 2018. We divested these assets during the fourth quarter of 2019. During 2018, we also recorded impairment expense of $82.0 million associated with certain of our non-core offshore gas assets in the Gulf of Mexico due to a change in contractual arrangements during the fourth quarter. Included in this amount is the acceleration in timing of the abandonment of one of our offshore hub platforms and pipelines and the write-off of its associated asset retirement obligation assets. The fair value of our assets was determined based on present value techniques. Asset Retirement Obligations We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. For any AROs acquired, we record AROs based on the fair value measurement assigned during the preliminary purchase price allocation. A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2017 $ 198,187 Accretion expense 10,509 Revisions in timing and estimated costs of AROs 44,319 Settlements (13,150 ) December 31, 2018 239,865 Accretion expense 9,402 Revisions in timing and estimated costs of AROs (20,529 ) Settlements (53,657 ) December 31, 2019 $ 175,081 At December 31, 2019 and December 31, 2018 , $26.6 million and $67.5 million are included as current in "Accrued liabilities" on our Consolidated Balance Sheets, respectively. Revisions in timing and estimated costs during 2019 and 2018 are primarily attributable to the accelerated timing and revised costs associated with the abandonment of certain of our non-core offshore gas assets in the Gulf of Mexico. The remainder of the ARO liability at each period is included in "Other long-term liabilities" on our Consolidated Balance Sheet. With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated: 2020 $ 8,860 2021 $ 8,939 2022 $ 9,417 2023 $ 10,081 2024 $ 10,792 Certain of our unconsolidated affiliates have AROs recorded at December 31, 2019 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.

Equity Investees

Equity Investees	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Investees	Equity Investees We account for our ownership in our joint ventures under the equity method of accounting (see Note 2 for a description of these investments). The price we pay to acquire an ownership interest in a company may exceed or be less than the underlying book value of the capital accounts we acquire. At December 31, 2019 and 2018 , the unamortized differences in carrying value totaled $350.9 million and $366.4 million , respectively. We amortize the differences in carrying value as a change in equity earnings. The following table presents information included in our Consolidated Financial Statements related to our equity investees. Year Ended December 31, 2019 2018 2017 Genesis’ share of operating earnings $ 71,975 $ 59,255 $ 66,814 Amortization of differences attributable to Genesis' carrying value of equity investments (15,491 ) (15,629 ) (15,768 ) Net equity in earnings $ 56,484 $ 43,626 $ 51,046 Distributions received $ 77,331 $ 71,714 $ 82,898 The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis): December 31, 2019 2018 BALANCE SHEET DATA: Assets Current assets $ 44,129 $ 34,005 Fixed assets, net 321,752 346,864 Other assets 16,739 15,469 Total assets $ 382,620 $ 396,338 Liabilities and equity Current liabilities $ 20,081 $ 18,897 Other liabilities 252,331 250,742 Equity 110,208 126,699 Total liabilities and equity $ 382,620 $ 396,338 Year Ended December 31, 2019 2018 2017 INCOME STATEMENT DATA: Revenues $ 209,674 $ 180,056 $ 191,078 Operating Income $ 155,920 $ 129,160 $ 139,604 Net Income $ 139,436 $ 115,669 $ 134,479 Poseidon's revolving credit facility

Intangible Assets, Goodwill and

Intangible Assets, Goodwill and Other Assets	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets, Goodwill and Other Assets	Intangible Assets, Goodwill and Other Assets Intangible Assets The following table reflects the components of intangible assets being amortized at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Intangible associated with lease (1) 15 — — — 13,260 5,407 7,853 Marine contract intangibles 5 27,800 23,033 4,767 27,800 17,593 10,207 Offshore pipeline contract intangibles 19 158,101 36,752 121,349 158,101 28,431 129,670 Other 9 34,291 21,480 12,811 31,747 16,875 14,872 Total $ 220,192 $ 81,265 $ 138,927 $ 230,908 $ 68,306 $ 162,602 (1) Intangible assets associated with a lease in our onshore facilities & transportation segment are now classified as part of our Right or Use Assets, net as part of our adoption of ASC 842 as of January 1, 2019 ( Note 4 ). The marine contract intangible primarily relates to the contracts we assumed in the purchase of the M/T American Phoenix in November 2014. The offshore pipeline contract intangibles relate to customer contracts surrounding certain transportation agreements with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline. We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. All of our current intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $18.7 million , $21.8 million and $23.6 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2020 2021 2022 2023 2024 Marine contract intangibles 4,538 37 35 34 33 Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 2,453 2,168 2,010 1,621 1,421 Total $ 15,312 $ 10,526 $ 10,366 $ 9,976 $ 9,775 Goodwill The carrying amount of goodwill in our sodium minerals and sulfur services segment was $301.9 million in December 31, 2019 and 2018 . During 2018, we recognized a goodwill impairment loss of $23.1 million related to our onshore facilities and transportation segment during the period. The goodwill impairment was specifically related to our supply and logistics reporting unit, that primarily includes our legacy crude oil and refined products marketing and trucking businesses. Due to our efforts to rightsize these businesses, along with the volatility of crude oil prices and the impact this volatility has on the availability of crude oil and heavy refined products for us to market, the fair value of the reporting unit was determined to be lower than the carrying value of the reporting unit, including goodwill. The fair value was derived using a discounted cash flow present value technique. Other Assets Other assets consisted of the following: December 31, 2019 2018 CO 2 volumetric production payments, net of amortization $ — $ 890 Deferred marine charges, net (1) 24,098 28,175 Contract assets (2) 54,232 72,241 Other deferred costs 15,755 20,401 Other assets, net of amortization $ 94,085 $ 121,707 (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 ) (2) See Revenue Recognition ( Note 3 ) for discussion on the circumstances that result in the recognition of contract assets. The CO 2 assets were being amortized on a units-of-production method and became fully amortized as of December 31, 2019.

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt At December 31, 2019 and 2018 , our obligations under debt arrangements consisted of the following: December 31, 2019 December 31, 2018 Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Senior secured credit facility $ 959,300 $ — $ 959,300 $ 970,100 $ — $ 970,100 6.750% senior unsecured notes 750,000 9,349 740,651 750,000 12,763 737,237 6.000% senior unsecured notes 400,000 3,557 396,443 400,000 4,624 395,376 5.625% senior unsecured notes 350,000 3,923 346,077 350,000 4,820 345,180 6.500% senior unsecured notes 550,000 7,020 542,980 550,000 8,241 541,759 6.250% senior unsecured notes 450,000 $ 6,214 443,786 450,000 7,189 442,811 Total long-term debt $ 3,459,300 $ 30,063 $ 3,429,237 $ 3,470,100 $ 37,637 $ 3,432,463 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Consolidated Balance Sheet) were $7.6 million and $10.8 million as of December 31, 2019 and December 31, 2018, respectively. Senior Secured Credit Facility The key terms for rates under our $1.7 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows: • The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At December 31, 2019 , the applicable margins on our borrowings were 1.50% for alternate base rate borrowings and 2.50% for Eurodollar rate borrowings. • Letter of credit fees range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2019 , our letter of credit rate was 2.50% . • We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio ( 0.50% at December 31, 2019 ). • Our credit facility contains a $300 million accordion feature, giving us the ability to expand the size of the facility up to $2.0 billion for acquisitions or growth projects, subject to lender consent. Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics—a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to EBITDA (as defined and adjusted in accordance with the credit facility) and cannot exceed 5.50 to 1.00 as of December 31, 2019. Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot exceed 3.75 to 1.00 . Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense and must be greater than 3.00 to 1.00 ( 2.75 to 1.00 during an acquisition period). At December 31, 2019 , we had $959.3 million borrowed under our credit facility, with $4.3 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $1.1 million was outstanding at December 31, 2019 . Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of May 9, 2022 . The total amount available for borrowings under our credit facility at December 31, 2019 was $739.6 million , subject to compliance with covenants. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Senior Unsecured Notes On February 8, 2013 , we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes"). On December 11, 2017, $204.8 million of these notes were validly tendered and repaid upon the issuance of our $450 million unsecured notes issued on December 11, 2017 as discussed below. A total loss of approximately $6.2 million for the tender is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations as of December 31, 2017. On February 15, 2018, we redeemed our remaining 2021 Notes in full at a redemption price of 101.438% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. We incurred a total loss of approximately $3.3 million relating to the extinguishment of those notes (including the write-off of the related unamortized debt issuance costs), which loss is recorded as "Other income/(expense), net" in our Consolidated Statements of Operations for the year ended December 31, 2018. On May 15, 2014 , we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due December 15, 2024 (the "2024 Notes"). Our 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. Our 2024 Notes mature on June 15, 2024 . The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes. On May 21, 2015, we issued $ 400 million in aggregate principal amount of 6.00% senior unsecured notes due May 15, 2023 (the "2023 Notes"). Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Our 2023 Notes mature on May 15, 2023. We used a portion of the proceeds from those notes to effectively redeem all of our outstanding $350 million , 7.875% senior unsecured notes due 2018, using a combination of public tender offer and our redemption rights relating to those notes. On July 23, 2015 , we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due August 1, 2022 (the "2022 Notes"). Interest payments are due on February 1 and August 1 of each year with the initial interest payment due February 1, 2016. Our 2022 Notes mature on August 1, 2022 . That issuance generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for our Enterprise acquisition. On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes due October 1, 2025 (the "2025 Notes"). Interest payments are due April 1 and October 1 of each year with the initial interest payment due April 1, 2018. That issuance generated net proceeds of $540.1 million , net of issuance costs incurred. Our 2025 Notes mature on October 1, 2025 . The net proceeds were used to fund a portion of the purchase price for our acquisition of our Alkali Business. On December 11, 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due May 15, 2026 (the "2026 Notes"). Interest payments are due May 15 and November 15 of each year with the initial interest payment due May 15, 2018. That issuance generated net proceeds of $441.8 million , net of issuance costs incurred. We used $204.8 million of the net proceeds to redeem the portion of the 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes") that were validly tendered and the remaining net proceeds to repay a portion of the borrowings outstanding under our revolving credit facility. We have the right to redeem each of our series of notes beginning on specified dates as summarized below, at a premium to the face amount of such notes that varies based on the time remaining to maturity on such notes. Additionally, we may redeem up to 35% of the principal amount of each of our series of notes with the proceeds from an equity offering of our common units during certain periods. A summary of the applicable redemption periods is provided in the table below. 2022 Notes (1) 2023 Notes 2024 Notes 2025 Notes 2026 Notes Redemption right beginning on August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 (1) Refer to Note 26 for discussion surrounding our tender and redemption of our 2022 Notes, along with the issuance of our 2028 Notes during the first quarter of 2020. Guarantees of our 2022, 2023, 2024, 2025 and 2026 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not a restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers and any other guarantor. Covenants and Compliance Our credit agreement and the indentures governing the senior notes contain cross-default provisions. Our credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, those agreements contain various covenants limiting our ability to, among other things: • incur indebtedness if certain financial ratios are not maintained; • grant liens; • engage in sale-leaseback transactions; and • sell substantially all of our assets or enter into a merger or consolidation. A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not restricted. As of December 31, 2019 , we were in compliance with the financial covenants contained in our credit facility and indentures.

Partners' Capital, Mezzanine Eq

Partners' Capital, Mezzanine Equity and Distributions	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Partners' Capital, Mezzanine Equity and Distributions	Partners’ Capital, Mezzanine Equity and Distributions At December 31, 2019 , our outstanding equity consisted of 122,539,221 Class A common units and 39,997 Class B common units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and, accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to certain exceptions. At December 31, 2019, we had 25,336,778 Class A Convertible Preferred Units outstanding, which are discussed below in further detail. Distributions Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter: • less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to: • provide for the proper conduct of our business; • comply with applicable law, any of our debt instruments, or other agreements; or • provide funds for distributions to our common and preferred unitholders for any one or more of the next four quarters; • plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. We paid common unitholders distributions in 2020 , 2019 and 2018 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2017 4th Quarter February 14, 2018 $ 0.5100 $ 62,515 2018 1st Quarter May 15, 2018 $ 0.5200 $ 63,741 2nd Quarter August 14, 2018 $ 0.5300 $ 64,967 3rd Quarter November 14, 2018 $ 0.5400 $ 66,193 4th Quarter February 14, 2019 $ 0.5500 $ 67,419 2019 1st Quarter May 15, 2019 $ 0.5500 $ 67,419 2nd Quarter August 14, 2019 $ 0.5500 $ 67,419 3rd Quarter November 14, 2019 $ 0.5500 $ 67,419 4th Quarter February 14, 2020 $ 0.5500 $ 67,419 Equity Issuances and Contributions Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs. On March 24, 2017 , we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of offering costs, of approximately $140.5 million from that offering. The new common units issued in 2017 to the public for cash were as follows: Period Purchaser of Common Units Units Gross Unit Price Issuance Value Costs Net Proceeds March 2017 Public 4,600 $ 30.65 $ 140,990 $ (477 ) $ 140,513 Class A Convertible Preferred Units On September 1, 2017, we sold $750 million of Class A convertible preferred units ("preferred units") in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our preferred units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those preferred units. Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496 ), yielding a quarterly rate of 2.1875% (or $0.7374 ), subject to certain adjustments. With respect to any quarter ending on or prior to March 1, 2019, we had the option to pay to the holders of our preferred units the applicable distribution amount in cash, preferred units, or any combination thereof. If we elected to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units would equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We elected to pay all distributions from inception through March 1, 2019 with additional preferred units. For the quarter ended March 31, 2019, we paid a portion of our distribution in cash, and a portion in preferred units. For each quarter ending after March 1, 2019, we paid all distribution amounts in respect of our preferred units in cash. From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of outstanding preferred units into our common units, subject to certain conditions; provided, however, that we will not be permitted to convert more than 7,416,498 of our preferred units in any consecutive twelve-month period. At any time after September 1, 2020, if we have fewer than 592,768 of our preferred units outstanding, we will have the right to convert each outstanding preferred unit into our common units at a conversion rate equal to the greater of (i) the then-applicable conversion rate and (ii) the quotient of (a) the Issue Price and (b) 95% of the volume-weighted average price of our common units for the 30-trading day period ending prior to the date that we notify the holders of our outstanding preferred units of such conversion. Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the holders of our common units is payable in cash, our preferred units will automatically convert into common units at a conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the product of (A) the sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our preferred units, and (B) a premium factor (ranging from 115% to 101% depending on when such transaction occurs) plus a prorated portion of unpaid partial distributions, and (ii) the volume weighted average price of the common units for the 30 trading days prior to the execution of definitive documentation relating to such change of control. In connection with other change of control events that do not meet the 90% cash consideration threshold described above, each holder of our preferred units may elect to (a) convert all of its preferred units into our common units at the then applicable conversion rate, (b) if we are not the surviving entity (or if we are the surviving entity, but our common units will cease to be listed), require us to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or if we are unable to cause such substantially equivalent securities to be issued, to convert its preferred units into common units in accordance with clause (a) above or exchanged in accordance with clause (d) below or convert at a specified conversion rate), (c) if we are the surviving entity, continue to hold our preferred units or (d) require us to exchange our preferred units for cash or, if we so elect, our common units valued at 95% of the volume-weighted average price of our common units for the 30 consecutive trading days ending on the fifth trading day immediately preceding the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101% and (y) the Issue Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points ; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25% of the then outstanding preferred units. Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110% , prior to September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its preferred units into common units initially on a one -for-one basis (subject to customary adjustments and an adjustment for accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a change of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser amount if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us. If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters, whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any distributions (subject to a limited exceptions for pro rata distributions on our preferred units and parity securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our preferred units with respect to rights upon distribution and/or liquidation (including our common units), or (b) issue any such junior or parity securities. If we fail to pay in full any preferred unit distribution after March 1, 2019 in respect of any two quarters, whether or not consecutive, then the preferred unit distribution amount will be reset to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to the then-current annualized distribution rate plus 200 basis points until such default is cured. In addition to their right to veto a Rate Reset Election under certain circumstances, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units; (ii) the right to purchase up to 50% of any parity securities on substantially the same terms offered to other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of our preferred units, and (iii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019. The Rate Reset Election of these preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. See further information in Note 19 . The preferred units themselves are classified as mezzanine capital on our Consolidated Balance Sheet. Accounting for the Class A Convertible Preferred Units Our preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event which is outside of our control. Therefore, we present them as temporary equity in the mezzanine section of the Consolidated Balance Sheet. The preferred units have been recorded at their issuance date fair value, net of issuance costs. Because our preferred units are not currently redeemable and we do not have plans or expect any events which constitute a change of control in our partnership agreement, we present our preferred units at their initial carrying amount. However, we would be required to adjust that carrying amount if it becomes probable that we would be required to redeem our preferred units. Initial and Subsequent Measurement We initially recognized our preferred units at their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of our preferred units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our preferred units to the redemption value over a period of time comprising the date the redemption first becomes probable and the date the units can first be redeemed. As discussed above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long term liabilities on the Consolidated Balance Sheet as described below (as of the inception date): September 1, 2017 Transaction price, gross $ 750,000 Transaction cost to other third parties (23,581 ) Transaction price, net 726,419 Allocation of Net Transaction Price Preferred Units, net 691,969 Preferred Distribution Rate Reset Election ( Note 19 ) 34,450 $ 726,419 Preferred unit distributions are recognized on the date in which they are declared. Paid in kind distributions were declared and issued as follows: Distribution Declared Date Issued Number of Units Total Amount 2017 November 2017 November 14, 2018 162,234 $ 5,469 2018 January 2018 February 14, 2018 490,252 $ 16,526 April 2018 May 15, 2018 500,967 $ 16,888 July 2018 August 14, 2018 511,934 $ 17,257 October 2018 November 14, 2018 523,132 $ 17,635 2019 January 2019 February 14, 2019 534,576 $ 18,021 April 2019 May 15, 2019 364,180 $ 12,277 We paid the following cash distributions to our preferred unitholders: Distribution For Date Paid Per Unit Total 2019 1 st Quarter May 15, 2019 $ 0.2458 $ 6,138 2 nd Quarter August 14, 2019 $ 0.7374 $ 18,684 3 rd Quarter November 14, 2019 $ 0.7374 $ 18,684 4 th Quarter February 14, 2020 $ 0.7374 $ 18,684 The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2019: Class A Convertible Preferred Units Units $ December 31, 2016 — $ — Issuance of Preferred Units, net 22,249,494 726,419 Allocation to Preferred Distribution Rate Reset Election ( Note 19 ) — (34,450 ) Distributions paid-in-kind 162,234 5,469 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (287 ) Balance as of December 31, 2017 22,411,728 $ 697,151 Distributions paid-in-kind 2,026,294 68,306 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (3,991 ) Balance as of December 31, 2018 24,438,022 $ 761,466 Distributions paid-in-kind 898,756 30,298 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (1,649 ) Balance as of December 31, 2019 25,336,778 $ 790,115 Net income (loss) attributable to common unitholders is reduced by Preferred Unit distributions that accumulated during the period. During 2019, net income attributable to common unitholders was reduced by $74.5 million as a result of distributions that accumulated during the period. Redeemable Noncontrolling Interests On September 23, 2019, we, through a subsidiary, Genesis Alkali Holdings Company, LLC (“Alkali Holdings”), entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain investment fund entities affiliated with GSO Capital Partners LP (collectively, the “Sponsor”) purchased $55,000,000 and committed to purchase, during a three-year commitment period, up to a total of $350,000,000 (the “Preferred Commitment”) of preferred units in Alkali Holdings, the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the net proceeds from the preferred units to fund up to 100% of the anticipated cost of expansion of the Granger facility. As of December 31, 2019 , we received cash of $122.9 million for the $130 million of preferred units issued to date net of issuance costs, which was inclusive of our transaction related expenses and one-time commitment fee. The Sponsor has the right to a quarterly distribution equal to 10% per annum on the liquidation preference of each preferred unit. The liquidation preference is defined as one thousand dollars per preferred unit, plus any accrued and unpaid distributions (including as a result of any distributions paid in kind). Distributions are payable quarterly within 45 days after the end of the fiscal quarter. Distributions may be paid in-kind in lieu of cash distributions during the first 36 months following the September 23, 2019 initial closing date. Subsequent to the payment-in-kind period, all distributions must be paid in cash. In addition to the quarterly distributions paid to the Sponsor, Alkali Holdings will distribute all of its distributable cash to the Partnership each quarter, which is equal to all cash and cash equivalents in the operating accounts of Alkali Holdings less cash reserves and a minimum $5 million cash balance to be maintained for working capital needs. From time to time after we have drawn at least $250 million of our Preferred Commitment, we have the option to redeem the outstanding preferred units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a predetermined fixed internal rate of return amount or a multiple of invested capital metric, net of cash distributions paid to date ("Base Preferred Return"). Additionally, if all outstanding preferred units are being redeemed, we have not drawn at least $250 million of our Preferred Commitment, and the Sponsor is not a "defaulting member" under the LLC Agreement, the Sponsor has the right to a make-whole amount on the number of undrawn preferred units. The Sponsor is obligated to purchase a minimum of $250 million of preferred units unless certain customary closing conditions are not satisfied, including the existence of a triggering event or a material uncured breach of the Securities Purchase Agreement by Alkali Holdings. A triggering event would occur if Alkali Holdings fails to pay cash distributions subsequent to the paid-in-kind period, fails to redeem preferred units when required to by a change of control event, or if any preferred units remain outstanding on the six year anniversary date, amongst other events. The preferred units must be redeemed, in whole or in part, following certain change of control events, fundamental changes, or the liquidation, winding up, or dissolution of Alkali Holdings and, as applicable, the Partnership. If such an event were to occur, the preferred units would rank senior to Alkali Holdings common units and any class or series of equity of Alkali Holdings established after the issuance of the preferred units. At any time following the sixth anniversary of the Securities Purchase Agreement, or following the occurrence of certain triggering events, if the preferred units issued and outstanding have not been redeemed in full for cash, the Sponsor has the right to gain control of the board of Alkali Holdings and effectuate a monetization event using its reasonable good faith efforts to maximize the consideration received to the holders of our common units, including the sale of Alkali Holdings (including all of its equity or assets and all of its equity in its subsidiaries), the proceeds of which would first be used to redeem the preferred units at the Base Preferred Return prior to any distribution to us. Pursuant to the LLC Agreement, the Board of Managers (the "Board") for Alkali Holdings will consist of 5 managers, including 3 designated by the Partnership, 1 designated by the Sponsor, and 1 independent manager. The independent manager is entitled to only attend Board meetings if the Board is required to vote on matters related to a bankruptcy of Alkali Holdings, and is permitted to only vote on such matters. See Note 25 for additional information regarding our non-guarantor subsidiaries. Accounting for Redeemable Noncontrolling Interests Classification The preferred units issued and outstanding are accounted for as a redeemable noncontrolling interest in the mezzanine section on our Consolidated Balance Sheet due to the redemption features for a change of control. Initial and Subsequent Measurement We recorded the preferred units at their issuance date fair value, net of issuance costs. The fair value as of December 31, 2019 represents the carrying amount based on the issued and outstanding preferred units most probable redemption event on the six year anniversary of the closing, which is the predetermined internal rate of return measure accreted using the effective interest method to the redemption value. Net Income Attributable to Genesis Energy, L.P. for the year ended December 31, 2019 includes $2.3 million of adjustments, of which $1.8 million was allocated to the distribution paid in-kind on the outstanding preferred units and $0.5 million was attributable to redemption accretion value adjustments from the closing date to December 31, 2019 . We elected to pay distributions for the period ending September 30, 2019 and December 31, 2019 in-kind to our preferred unitholders. These in-kind distributions increase the unitholders liquidation preference on each preferred unit. As of the reporting date, there are no triggering, change of control, early redemption or monetization events that are probable that would require us to revalue the preferred units. If the preferred units were redeemed on the reporting date of December 31, 2019 , the redemption amount would be equal to $192.5 million , which would be the multiple of invested capital metric applied to the preferred units outstanding plus the make-whole amount on the undrawn minimum preferred units. The following table shows the change in our redeemable noncontrolling interests from initial measurement at September 23, 2019 to December 31, 2019 : Year Ended December 31 2019 Issuance of Preferred Units $ 55,000 Issuance costs (5,600 ) Balance as of September 23, 2019 49,400 Issuance of preferred units, net of issuance costs 73,500 Distribution paid-in-kind 1,778 Redemption accretion 455 Balance as of December 31, 2019 $ 125,133

Net Income (Loss) Per Common Un

Net Income (Loss) Per Common Unit	12 Months Ended
	Dec. 31, 2019
Net Income per Common Unit [Abstract]
Net Income (Loss) Per Common Unit	Net Income (Loss) Per Common Unit Basic net income per common unit is computed by dividing Net Income Attributable to Genesis Energy, L.P., after considering income attributable to our Class A preferred unitholders, by the weighted average number of common units outstanding. The dilutive effect of the Class A Convertible Preferred units is calculated using the if-converted method. Under the if-converted method, the Class A Preferred units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the years ended December 31, 2019 , 2018, and 2017, the effect of the assumed conversion of our Class A convertible preferred units was anti-dilutive and was not included in the computation of diluted earnings per unit. The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts): Year Ended December 31 2019 2018 2017 Net Income (Loss) Attributable to Genesis Energy L.P. $ 95,999 $ (6,075 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (74,467 ) (69,801 ) (21,995 ) Net Income (Loss) Available to Common Unitholders $ 21,532 $ (75,876 ) $ 60,652 Weighted Average Outstanding Units 122,579 122,579 121,546 Basic and Diluted Net Income (Loss) per Common Unit $ 0.18 $ (0.62 ) $ 0.50

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information We currently manage our businesses through four divisions that constitute our reportable segments: • 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 of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, NaHS; • Onshore facilities and transportation – terminaling, 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. Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States. We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation, depletion, and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total Year Ended December 31, 2019 Segment Margin (a) $ 320,023 $ 223,908 $ 111,412 $ 57,919 $ 713,262 Capital expenditures (b) $ 17,809 $ 107,837 $ 6,576 $ 40,820 $ 173,042 Revenues: External customers $ 318,116 $ 1,113,623 $ 824,148 $ 224,933 $ 2,480,820 Intersegment (c) — (7,636 ) (3,076 ) 10,712 $ — Total revenues of reportable segments $ 318,116 $ 1,105,987 $ 821,072 $ 235,645 $ 2,480,820 Year Ended December 31, 2018 Segment Margin (a) $ 285,014 $ 260,488 $ 119,918 $ 47,338 $ 712,758 Capital expenditures (b) $ 4,703 $ 74,712 $ 51,110 $ 30,868 $ 161,393 Revenues: External customers $ 284,544 $ 1,181,578 $ 1,240,382 $ 206,266 $ 2,912,770 Intersegment (c) — (7,144 ) (6,527 ) 13,671 $ — Total revenues of reportable segments $ 284,544 $ 1,174,434 $ 1,233,855 $ 219,937 $ 2,912,770 Year Ended December 31, 2017 Segment Margin (a) $ 317,540 $ 130,333 $ 96,376 $ 50,294 $ 594,543 Capital expenditures (b) $ 8,815 $ 1,354,469 $ 149,123 $ 68,414 $ 1,580,821 Revenues: External customers $ 319,455 $ 470,789 $ 1,044,083 $ 194,050 $ 2,028,377 Intersegment (c) (1,216 ) (8,167 ) (1,854 ) 11,237 $ — Total revenues of reportable segments $ 318,239 $ 462,622 $ 1,042,229 $ 205,287 $ 2,028,377 Total assets by reportable segment were as follows: December 31, 2019 December 31, 2018 December 31, 2017 Offshore pipeline transportation $ 2,306,946 $ 2,359,013 $ 2,486,803 Sodium minerals and sulfur services 2,019,905 1,844,845 1,848,188 Onshore facilities and transportation 1,457,190 1,431,910 1,927,976 Marine transportation 772,383 800,243 824,777 Other assets 41,217 43,060 49,737 Total consolidated assets $ 6,597,641 $ 6,479,071 $ 7,137,481 (a) A reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P. for each year 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. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. (c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions. Reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P.: Year Ended December 31 2019 2018 2017 Total Segment Margin $ 713,262 $ 712,758 $ 594,543 Corporate general and administrative expenses (52,755 ) (64,683 ) (60,029 ) Depreciation, depletion, amortization and accretion (308,115 ) (317,186 ) (262,021 ) Interest expense (219,440 ) (229,191 ) (176,762 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (20,847 ) (28,088 ) (31,852 ) Non-cash items not included in Segment Margin (14,642 ) 9,698 (14,305 ) Cash payments from direct financing leases in excess of earnings (8,421 ) (7,633 ) (6,921 ) Loss on extinguishment of debt — (3,339 ) (6,242 ) Differences in timing of cash receipts for certain contractual arrangements (2) 8,478 6,629 17,540 Gain on sales of assets — 42,264 40,311 Other, net — — (2,985 ) Non-cash provision for leased items no longer in use 1,367 476 (12,589 ) Income tax (expense) benefit (655 ) (1,498 ) 3,959 Redeemable noncontrolling interest redemption value adjustments (3) (2,233 ) — — Impairment expense — (126,282 ) — Net income (loss) attributable to Genesis Energy, L.P. $ 95,999 $ (6,075 ) $ 82,647 (1) Includes distributions attributable to the period and received during or promptly following such period. (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. (3) Includes distributions paid in kind attributable to the period and accretion on the redemption feature.

Transactions with Related Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties Transactions with related parties were as follows: Year Ended December 31, 2019 2018 2017 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ — $ 1,233 $ 2,820 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,669 12,557 12,357 Revenues from product sales to ANSAC 367,133 373,606 124,536 Expenses: Amounts paid to our CEO in connection with the use of his aircraft $ 660 $ 660 $ 660 Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2) 975 994 986 Charges for services from ANSAC 4,446 5,284 2,242 (1) We owned a 50% interest in Sandhill Group, LLC which was sold in the third quarter of 2018. (2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft, including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long-term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than what we could have expected to obtain in an arms-length transaction. Transactions with Unconsolidated Affiliates Poseidon We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the years ended December 31, 2019 , 2018 and 2017 reflect $8.9 million , $8.6 million and $8.4 million , respectively, of fees we earned through the provision of services under that agreement. At December 31, 2019 , and 2018 , Poseidon Oil Pipeline Company, LLC owed us $2.4 million for services rendered. ANSAC We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. (ANSAC), an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. ANSAC passes its costs through to its members using a pro rata calculation based on sales. Those costs include sales and marketing, employees, office supplies, professional fees, travel, rent, and certain other costs. Those transactions do not necessarily represent arm's length transactions and may not represent all costs we would otherwise incur if we operated the Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport. ANSAC is considered a variable interest entity (VIE) as we do experience certain risks and rewards from our relationship with them. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC. The ANSAC membership agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. As of December 31, 2019, such amount is not estimable. Net sales to ANSAC were $367.1 million , $373.6 million and $124.5 million for the years ended December 31, 2019 , 2018 and 2017 . The costs charged to us by ANSAC, included in operating costs, were $4.4 million , $5.3 million and $2.2 million for the years ended December 31, 2019 , 2018 and 2017 . The 2017 period includes net sales and costs from September 1, 2017 (our acquisition date) to December 31, 2017. As of December 31, 2019 and 2018 , our receivables from and payables to ANSAC were: December 31 December 31 2019 2018 Receivables: ANSAC $ 68,075 $ 60,594 Payables: ANSAC $ 2,103 $ 815

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following table provides information regarding the net changes in components of operating assets and liabilities: Year Ended December 31, 2019 2018 2017 (Increase) decrease in: Accounts receivable $ (80,126 ) $ 130,573 $ (140,948 ) Inventories 7,659 20,963 49,055 Deferred charges 4,093 (5,826 ) (3,622 ) Other current assets (4,874 ) 9,337 (410 ) Increase (decrease) in: Accounts payable 81,915 (130,991 ) 97,569 Accrued liabilities (79,765 ) (26,208 ) 8,512 Net changes in components of operating assets and liabilities $ (71,098 ) $ (2,152 ) $ 10,156 Payments of interest and commitment fees were $212.4 million , $228.3 million and $168.3 million during the years ended December 31, 2019 , 2018 and 2017 , respectively. We capitalized interest of $3.7 million , $3.4 million and $15.0 million during the years ended December 31, 2019 , 2018 and 2017 . During the years ended December 31, 2019 , 2018 and 2017 , we paid taxes of $0.8 million , $0.2 million and $1.0 million . At December 31, 2019 , 2018 and 2017 , we had incurred liabilities for fixed and intangible asset additions totaling $22.6 million , $9.4 million and $39.7 million , respectively, which had not been paid at the end of the year. Therefore, these amounts were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

Equity-Based Compensation Plans

Equity-Based Compensation Plans	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Equity-Based Compensation Plans	Equity-Based Compensation Plans 2010 Long Term Incentive Plan In 2010, we adopted the 2010 Long-Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the awards of phantom units and distribution equivalent rights to members of our board of directors and employees who provide services to us. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met. Distribution equivalent rights (“DERs”) are tandem rights to receive on a quarterly basis a cash amount per phantom unit equal to the amount of cash distributions paid per common unit. The 2010 Plan is administered by the Governance, Compensation and Business Development Committee (the “G&C Committee”) of our board of directors. The G&C Committee (at its discretion) designates participants in the 2010 Plan, determines the types of awards to grant to participants, determines the number of units to be covered by any award, and determines the conditions and terms of any award including vesting, settlement and forfeiture conditions. The compensation cost associated with the phantom units is re-measured each reporting period based on the market value of our common units, and is recognized over the vesting period. The liability recorded for the estimated amount to be paid to the participants under the 2010 Plan is adjusted to recognize changes in the estimated compensation cost and vesting. Management’s estimates of the fair value of these awards granted in 2019 are adjusted for assumptions about expected forfeitures of units prior to vesting. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. During 2019 , we granted 29,606 phantom units with tandem DERs at a weighted average grant fair value of $21.28 per unit. During 2018 , we granted 28,484 phantom units with tandem DERs at a weighted average grant date fair value of $22.12 per unit. During 2017 , we granted 297,214 phantom units with tandem DERs at a weighted average grant date fair value of $32.37 per unit. The phantom units granted during 2019 and 2018 were made only to directors. Awards to management and other key employees during 2019 and 2018 were made under the 2018 LTIP plan, and were non-equity based awards. The phantom units granted during 2017 were both service-based and performance-based awards. The service-based awards vest on the third anniversary of the date of grant. Performance-based phantom unit awards granted in 2017 will vest on the third anniversary of issuance, in an amount ranging from 0% to 150% of the targeted number of phantom units, if certain quarterly cash distribution per common unit targets are achieved in the fourth quarter of 2020 . If the quarterly cash distribution per common unit is below the threshold target, all of the performance-based phantom units granted will be forfeited. A summary of our phantom unit activity for our service-based and performance-based awards is set forth below: Service-Based Awards Performance-Based Awards Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Unvested at December 31, 2018 195,939 $ 30.40 $ 5,958 378,006 $ 31.09 $ 11,754 Granted 29,606 $ 21.28 630 — $ — — Forfeited (1,098 ) $ 32.43 (36 ) (1,653 ) $ 32.43 (54 ) Settled (76,370 ) $ 31.79 (2,428 ) (213,582 ) $ 30.37 (6,486 ) Unvested at December 31, 2019 148,077 $ 27.85 $ 4,124 162,771 $ 32.02 $ 5,214 At December 31, 2019 , we estimated the unrecognized compensation cost of our phantom awards to be approximately $0.2 million to be recognized over a weighted average period of approximately 0.3 years. We recorded a charge of $1.8 million and $2.1 million to compensation expense for the years ended December 31, 2019 and 2018 , respectively. Our liability for these awards totaled $2.8 million and $3.3 million at December 31, 2019 and 2018 , respectively. Equity-Based Compensation Plan Expense Equity-based compensation expense during the three years ended December 31, 2019 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2019 2018 2017 Onshore facilities and transportation operating costs $ 250 $ 140 $ (1,137 ) Marine transportation operating costs 173 183 (483 ) Sodium minerals and sulfur services operating costs 140 112 (533 ) Offshore pipeline operating costs 269 297 (152 ) General and administrative expenses 1,087 1,239 (2,272 ) Total $ 1,919 $ 1,971 $ (4,577 )

Major Customers and Credit Risk

Major Customers and Credit Risk	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Major Customers and Credit Risk	Major Customers and Credit Risk Due to the nature of our onshore facilities and transportation operations, a disproportionate percentage of our trade receivables constitute obligations of refiners, large crude oil producers and integrated oil companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of accounts owed by integrated and large independent energy companies with stable payment histories. The credit risk related to contracts which are traded on the NYMEX is limited due to daily margin requirements and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. In 2019 and 2018 our largest customer was ANSAC, which accounted for 15% and 13% of total consolidated revenues, respectively. As discussed in Note 15 , we are a member of ANSAC, an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. Given this relationship, a large portion of our soda ash production is sold to ANSAC. As such, a disproportionate amount of our trade receivables and sales in our sodium minerals and sulfur services segment are related to ANSAC. During 2019 , 2018 and 2017 , Shell Oil Company was one of our largest customers, which accounted for 8% , 11% and 13% of total revenues, respectively. The revenues from Shell Oil Company in all years relate primarily to our onshore facilities and transportation operations.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity prices, primarily of crude oil, fuel oil and petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed. We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Consolidated Statement of Operations. In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets. Additionally, we utilize swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our operating costs. At December 31, 2019 , we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. Sell (Short) Contracts Buy (Long) Contracts Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 19 — Weighted average contract price per bbl $ 58.57 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 79 80 Weighted average contract price per bbl $ 60.25 $ 60.25 Natural gas swaps: Contract volumes (10,000 MMBTU) 503 — Weighted average price differential per MMBTU $ 0.38 — Natural gas futures: Contract volumes (10,000 MMBTU) 92 576 Weighted average contract price per MMBTU $ 2.27 $ 2.60 Crude oil options: Contract volumes (1,000 bbls) 40 18 Weighted average premium received/paid $ 1.03 $ 0.66 Financial Statement Impacts The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements. Derivative Instrument Hedged Risk Impact of Unrealized Gains and Losses Consolidated Balance Sheets Consolidated Statements of Operations Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories Excess, if any, over effective portion of hedge is recorded in Onshore facilities and transportation costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged Not qualifying or not designated as hedges under accounting guidance: Commodity hedges consisting of crude oil, heating oil and natural gas futures, forward contracts, swaps and call options Volatility in crude oil, natural gas and petroleum products prices - effect on market value of inventory or purchase commitments Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities Entire amount of change in fair value of derivative is recorded in Onshore facilities and transportation costs - product costs and Sodium minerals and sulfur services - operating costs Preferred Distribution Rate Reset Election This instrument is not related to a risk, but is rather part of a host contract with the issuance of our Preferred Units Derivative is recorded in Other long-term liabilities Entire amount of change in fair value of derivative is recorded in Other income (expense) Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities. The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2019 and 2018 : Fair Value of Derivative Assets and Liabilities Fair Value Consolidated Balance Sheets Location December 31, 2019 December 31, 2018 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 207 $ 3,431 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (207 ) (1,361 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ 2,070 Natural Gas Swap (undesignated hedge) Current Assets - Other 1,382 1,274 Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 4 $ 469 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (4 ) (44 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ 425 Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (51,515 ) $ (40,840 ) Natural Gas Swap (undesignated hedge) Current Liabilities - Accrued Liabilities — (125 ) Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (2,079 ) $ (1,361 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,064 1,361 Net amount of liabilities presented in the Consolidated Balance Sheets $ (1,015 ) $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (50 ) $ (44 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 50 44 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — (1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other. (2) Refer to Note 12 and Note 20 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative. Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of December 31, 2019 , we had a net broker receivable of approximately $0.9 million (consisting of initial margin of $0.8 million increased by $0.1 million of variation margin). As of December 31, 2018 , we had a net broker receivable of approximately $2.2 million (consisting of initial margin of $3.1 million decreased by $0.9 million of variation margin). At December 31, 2019 and December 31, 2018 , none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Preferred Distribution Rate Reset Election A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a Rate Reset Election to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points ; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. The Rate Reset Election of the preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other Income (Expense) in our Consolidated Statement of Operations. At December 31, 2019 , the fair value of this embedded derivative was a liability of $51.5 million . See Note 12 for additional information regarding our Class A convertible preferred units and the Rate Reset Election. Effect on Operating Results Amount of Gain (Loss) Recognized in Income Year Ended December 31 Consolidated Statements of Operations Location 2019 2018 2017 Commodity derivatives—futures and options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ (786 ) $ (544 ) $ 5,116 Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs (7,790 ) 3,914 (1,314 ) Total commodity derivatives $ (8,576 ) $ 3,370 $ 3,802 Natural Gas Swaps Sodium minerals and sulfur services operating costs 1,941 $ 1,906 $ — Preferred Distribution Rate Reset Election ( Note 20 ) Other Income (Expense) $ (9,026 ) $ 8,360 $ (10,472 ) We have no derivative contracts with credit contingent features.

Fair-Value Measurements

Fair-Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair-Value Measurements	Fair-Value Measurements We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value: (1) Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities; (2) Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and (3) Level 3 fair values are based on unobservable inputs in which little or no market data exists. As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 . December 31, 2019 December 31, 2018 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 211 $ 1,382 $ — $ 3,900 $ 1,274 $ — Liabilities $ (2,129 ) $ — $ — $ (1,405 ) $ (125 ) $ — Preferred Distribution Rate Reset Election $ — $ — $ (51,515 ) $ — $ — $ (40,840 ) 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: Balance as of December 31, 2017 $ (45,209 ) Net gain for the period including earnings 8,360 Allocation of Distribution Paid-in-kind (3,991 ) Balance as of December 31, 2018 (40,840 ) Net loss for the period included in earnings (9,026 ) Allocation of Distribution Paid-in-kind (1,649 ) Balance as of December 31, 2019 $ (51,515 ) Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy. The fair value of the swaps contracts was determined using market price quotations and a pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at December 31, 2019 . The fair value of embedded derivative feature is based on a valuation model that estimates the fair value of the convertible preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit price, a ten year history of the dividend yield, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as Other income (expense), net. See Note 19 for additional information on our derivative instruments. Nonfinancial Assets and Liabilities We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such assets within our Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3. Other Fair Value Measurements We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At December 31, 2019 our senior unsecured notes had a carrying value and fair value of $2.5 billion , compared to $2.5 billion and $2.3 billion , respectively at December 31, 2018 . The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans We sponsor a defined benefit pension plan for employees of our Alkali Business. We account for the Alkali Business pension plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus, the related assets and liability costs of the plan are recorded in the Consolidated Balance Sheet. Under the Alkali Business pension plan, each eligible employee will automatically become a participant upon completion of one year of credited service. Retirement benefits under this plan are calculated based on the total years of service of an eligible participant, multiplied by a specified benefit rate in effect at the termination of the plan participant's years of service. During 2019, we completed collective bargaining negotiations with our union employees. As a result, the pension plan was amended to increase the future benefit rate and pension supplement amounts. The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2019 2018 Change in benefit obligation: Benefit Obligation, beginning of year $ 24,511 $ 22,530 Service Cost 4,351 5,153 Interest Cost 1,340 862 Plan Amendment 6,569 — Actuarial (Gain) Loss 5,981 (3,816 ) Benefits Paid (461 ) (218 ) Benefit Obligation, end of year 42,291 24,511 Change in plan assets: Fair Value of Plan Assets, beginning of year 15,716 13,306 Actual Return (loss) on Plan Assets 4,025 (1,300 ) Employer Contributions 4,771 3,928 Benefits Paid (461 ) (218 ) Fair Value of Plan assets, end of year 24,051 15,716 Funded Status at end of period $ (18,240 ) $ (8,795 ) Amounts recognized in the Consolidated Balance Sheet: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (18,240 ) (8,795 ) Net Liability at end of year $ (18,240 ) $ (8,795 ) Amounts recognized in accumulated other comprehensive income (loss): Prior Service Cost 6,163 — Net actuarial (gain) loss 2,268 (939 ) Amounts recognized in accumulated other comprehensive income ( loss:) $ 8,431 $ (939 ) Estimated Future Cash Flows- The following employer contributions and benefit payments, which reflect expected future service, are expected to be paid as follows: Employer Contributions Expected 2020 Contributions by Employer $ 5,850 Future Expected Benefit Payments 2020 $ 824 2021 1,112 2022 1,343 2023 1,537 2024 1,714 2025-2029 11,250 Net Periodic Pension Costs- The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2019 2018 2017 Service Cost $ 4,351 $ 5,153 $ 1,749 Interest Cost 1,340 862 267 Expected Return on Assets (1,252 ) (973 ) (259 ) Amortization of Prior Service Cost 406 — — Total Net Periodic Benefit Costs (1) $ 4,845 $ 5,042 $ 1,757 (1) On September 1, 2017, we acquired our Alkali Business including the Company's defined benefit plan. The 2017 Net Periodic Benefit Cost represents the period of the year subsequent to our purchase of the Alkali Business resulting in a lower annual cost compared to 2019 and 2018, respectively. Significant Assumptions- Discount rates are determined annually and are based on rates of return of high-quality long-term fixed income securities currently available and expected to be available during the maturity of the pension benefits. The long-term rate of return estimation for the Alkali Business pension plan is based on a capital asset pricing model using historical data and a forecasted earnings model. An expected return on plan assets analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors. The Alkali Business pension plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan's management. The committee is responsible for the oversight and management of the plan's investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2019 December 31, 2018 Discount Rate 3.56 % 4.62 % Expected Long-term Rate of Return 6.06 % 6.41 % Rate of Compensation Increase N/A N/A The discount rate used to determine the net periodic cost at the beginning of the period was 4.62% . Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy established for the pension plan. The target allocation is designed to achieve long term objectives of return, mitigating risk, and considering expected cash flows. Pension plan asset allocations at December 31, 2019 by asset category are as follows: December 31, 2019 Target % Actual % Equity securities 41-60% 55 % Fixed income securities and other 40-60% 45 % A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2019 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents 1,311 — — $ 1,311 506 — — $ 506 Equity securities 13,192 — — $ 13,192 8,038 — — $ 8,038 Mutual and other exchange traded funds 9,548 — — $ 9,548 7,172 — — $ 7,172 24,051 — — $ 24,051 15,716 — — $ 15,716

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments and Guarantees We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can be made that such environmental releases may not substantially affect our business. Other Matters Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations or cash flows.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the federal income tax returns of each of our partners. A few of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay federal and state income taxes on these operations. As a result of the Tax Cuts and Jobs Act enacted on December 22, 2017, The Partnership remeasured its U.S. deferred tax assets and liabilities during the year ended December 31, 2017 and recorded a $5.3 million benefit relating to the U.S. federal corporate tax rate change. Our income tax (benefit) expense is as follows: Year Ended December 31, 2019 2018 2017 Current: Federal $ — $ — $ — State 591 810 100 Total current income tax expense $ 591 $ 810 $ 100 Deferred: Federal $ 930 $ 114 $ (5,530 ) State (866 ) 574 1,471 Total deferred income tax expense (benefit) $ 64 $ 688 $ (4,059 ) Total income tax expense (benefit) $ 655 $ 1,498 $ (3,959 ) Deferred income taxes relate to temporary differences based on tax laws and statutory rates that were enacted at the balance sheet date. Deferred tax assets and liabilities consist of the following: December 31, 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 12,557 $ 11,057 Other 927 434 Total long-term deferred tax asset 13,484 11,491 Valuation allowances (2,172 ) (1,758 ) Total deferred tax assets $ 11,312 $ 9,733 Deferred tax liabilities: Long-term: Fixed assets $ (1,958 ) $ (2,893 ) Intangible assets (20,730 ) (18,209 ) Other (1,264 ) (1,207 ) Total long-term liability (23,952 ) (22,309 ) Total deferred tax liabilities $ (23,952 ) $ (22,309 ) Total net deferred tax liability $ (12,640 ) $ (12,576 ) We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. The reconciliation between the Partnership's effective tax rate on income (loss) from operations and the statutory tax rate is as follows: Year Ended December 31, 2019 2018 2017 Income (loss) from operations before income taxes $ 100,721 $ (10,294 ) $ 78,120 Partnership income not subject to federal income tax (99,832 ) 10,824 (77,704 ) Income subject to federal income taxes $ 889 $ 530 $ 416 Tax expense at federal statutory rate $ 187 $ 111 $ 146 State income taxes, net of federal tax 729 1,285 1,396 Return to provision, federal and state (219 ) (128 ) (163 ) Other (42 ) 230 (68 ) Re-measurement of deferred taxes due to enacted tax rate change — — (5,270 ) Income tax expense (benefit) $ 655 $ 1,498 $ (3,959 ) Effective tax rate on income from operations before income taxes 1 % (15 )% (5 )% At December 31, 2019 , 2018 and 2017 , we had no uncertain tax positions.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Quarterly Financial Information (Unaudited)	Quarterly Financial Data (Unaudited) The table below summarizes our unaudited quarterly financial data for 2019 and 2018 . 2019 Quarters First Second Third Fourth Revenues from continuing operations $ 620,009 $ 634,785 $ 621,697 $ 604,329 Operating income $ 62,029 $ 86,948 $ 52,787 $ 70,939 Net income $ 15,947 $ 41,652 $ 17,807 $ 24,660 Net loss (income) attributable to noncontrolling interest $ 7 $ (1,532 ) $ 22 $ (331 ) Net income attributable to redeemable noncontrolling interest $ — $ — $ (272 ) $ (1,961 ) Net income attributable to Genesis Energy, L.P. $ 15,954 $ 40,120 $ 17,557 $ 22,368 Basic and diluted net income (loss) per common unit: Net income (loss) per common unit $ (0.02 ) $ 0.17 $ (0.01 ) $ 0.03 Cash distributions per common unit (1) $ 0.5500 $ 0.5500 $ 0.5500 $ 0.5500 2018 Quarters First Second Third Fourth Revenues from continuing operations $ 725,808 $ 752,388 $ 745,278 $ 689,296 Operating income $ 59,081 $ 60,900 $ 46,148 $ 4,119 Net income (loss) $ 7,898 $ 10,871 $ (1,634 ) $ (28,927 ) Net loss attributable to noncontrolling interest $ 136 $ 126 $ 1,311 $ 4,144 Net income (loss) attributable to Genesis Energy, L.P. $ 8,034 $ 10,997 $ (323 ) $ (24,783 ) Basic and diluted net loss per common unit: Net loss per common unit $ (0.07 ) $ (0.05 ) $ (0.15 ) $ (0.35 ) Cash distributions per common unit (1) $ 0.5200 $ 0.5300 $ 0.5400 $ 0.5500 (1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Condensed Consolidating Financial Information Disclosure	Condensed Consolidating Financial Information Our $2.5 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except the subsidiaries that hold our Alkali Business, Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the Partnership's debts, and the liabilities of our unrestricted subsidiaries do not constitute obligations of the Partnership except, in the case of the Alkali Business, to the extent agreed to in the services agreement between the Partnership and Alkali Holdings dated as of September 23, 2019. Genesis Energy Finance Corporation has no independent assets or operations. See Note 11 for additional information regarding our consolidated debt obligations. On September 23, 2019, the Company announced the expansion of its Granger facility which included designating the Alkali Business as unrestricted subsidiaries of the Company under our indentures. Following such designation, the Alkali Business no longer guarantees our notes. The Alkali Business was historically presented as guarantor subsidiaries in footnote 18 and because of such designation will now be presented as non-guarantor subsidiaries. The changes made did not impact the Company's previously reported consolidated net operating results, financial position, or cash flows. The condensed consolidating balance sheet as of December 31, 2018 and the condensed consolidating statements of operations and cash flows for the year ended December 31, 2018 and 2017 have been retrospectively adjusted to reflect these updates to our non-guarantor subsidiaries as though the Alkali Business had been presented as non-guarantor subsidiaries in all periods presented (consistent with our 8-K filed with the SEC on December 19, 2019). The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries: Condensed Consolidating Balance Sheet December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 7,269 $ 21,853 $ — $ 29,128 Restricted cash — — — 27,277 — 27,277 Other current assets 50 — 316,166 220,526 (73 ) 536,669 Total current assets 56 — 323,435 269,656 (73 ) 593,074 Fixed Assets, at cost — — 4,627,696 912,900 — 5,540,596 Less: Accumulated depreciation — — (1,089,246 ) (156,875 ) — (1,246,121 ) Net fixed assets — — 3,538,450 756,025 — 4,294,475 Mineral Leaseholds, net of accumulated depletion — — — 555,825 — 555,825 Goodwill — — 301,959 — — 301,959 Other assets, net of amortization 7,583 — 403,277 109,862 (180,008 ) 340,714 Advances to affiliates 3,039,468 — — 158,798 (3,198,266 ) — Equity investees — — 334,523 — — 334,523 Investments in subsidiaries 2,706,095 — 1,420,664 — (4,126,759 ) — Right of use assets, net — — 83,942 93,129 — 177,071 Total assets $ 5,753,202 $ — $ 6,406,250 $ 1,943,295 $ (7,505,106 ) $ 6,597,641 LIABILITIES AND CAPITAL Current liabilities $ 39,015 $ — $ 253,926 $ 122,673 $ (119 ) $ 415,495 Senior secured credit facility 959,300 — — — — 959,300 Senior unsecured notes, net of debt issuance costs 2,469,937 — — — — 2,469,937 Deferred tax liabilities — — 12,640 — — 12,640 Advances from affiliates — — 3,198,277 — (3,198,277 ) — Other liabilities 51,515 — 245,424 276,789 (179,878 ) 393,850 Total liabilities 3,519,767 — 3,710,267 399,462 (3,378,274 ) 4,251,222 Mezzanine Capital: Class A Convertible Preferred Units 790,115 — — — — 790,115 Redeemable noncontrolling interests — — — 125,133 — 125,133 Partners’ capital, common units 1,443,320 — 2,695,983 1,430,849 (4,126,832 ) 1,443,320 Accumulated other comprehensive income (loss) (1) — — — (8,431 ) — (8,431 ) Noncontrolling interests — — — (3,718 ) — (3,718 ) Total liabilities, mezzanine capital and partners’ capital $ 5,753,202 $ — $ 6,406,250 $ 1,943,295 $ (7,505,106 ) $ 6,597,641 (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. Condensed Consolidating Balance Sheet December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 4,924 $ 5,370 $ — $ 10,300 Other current assets 50 — 229,411 203,683 (165 ) 432,979 Total current assets 56 — 234,335 209,053 (165 ) 443,279 Fixed Assets, at cost — — 4,602,164 838,694 — 5,440,858 Less: Accumulated depreciation — — (926,830 ) (96,995 ) — (1,023,825 ) Net fixed assets — — 3,675,334 741,699 — 4,417,033 Mineral Leaseholds, net of accumulated depletion — — — 560,481 — 560,481 Goodwill — — 301,959 — — 301,959 Other assets, net 10,776 — 435,540 122,538 (167,620 ) 401,234 Advances to affiliates 3,305,568 — — 105,917 (3,411,485 ) — Equity investees — — 355,085 — — 355,085 Investments in subsidiaries 2,648,510 — 1,413,334 — (4,061,844 ) — Total assets $ 5,964,910 $ — $ 6,415,587 $ 1,739,688 $ (7,641,114 ) $ 6,479,071 LIABILITIES AND CAPITAL Current liabilities $ 39,342 $ — $ 177,104 $ 116,498 $ (110 ) $ 332,834 Senior secured credit facility 970,100 — — — — 970,100 Senior unsecured notes, net of debt issuance costs 2,462,363 — — — — 2,462,363 Deferred tax liabilities — — 12,576 — — 12,576 Advances from affiliates — — 3,411,515 — (3,411,515 ) — Other liabilities 40,840 — 174,249 211,590 (167,481 ) 259,198 Total liabilities 3,512,645 — 3,775,444 328,088 (3,579,106 ) 4,037,071 Mezzanine Capital Class A Convertible Preferred Units 761,466 — — — — 761,466 Partners' capital, common units 1,690,799 — 2,640,143 1,421,865 (4,062,008 ) 1,690,799 Accumulated other comprehensive income (loss) (1) — — — 939 — 939 Noncontrolling interests — — — (11,204 ) — (11,204 ) Total liabilities, mezzanine capital and partners’ capital $ 5,964,910 $ — $ 6,415,587 $ 1,739,688 $ (7,641,114 ) $ 6,479,071 (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. Condensed Consolidating Statement of Operations Year Ended December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 318,116 $ — $ — $ 318,116 Sodium minerals and sulfur services — — 260,675 852,949 (7,637 ) 1,105,987 Marine transportation — — 235,645 — — 235,645 Onshore facilities and transportation — — 802,735 18,337 — 821,072 Total revenues — — 1,617,171 871,286 (7,637 ) 2,480,820 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 713,577 1,327 — 714,904 Marine transportation operating costs — — 178,032 — — 178,032 Sodium minerals and sulfur services operating costs — — 200,845 690,484 (7,637 ) 883,692 Offshore pipeline transportation operating costs — — 68,167 (9,171 ) — 58,996 General and administrative — — 51,191 1,496 — 52,687 Depreciation, depletion and amortization — — 242,227 77,579 — 319,806 Total costs and expenses — — 1,454,039 761,715 (7,637 ) 2,208,117 OPERATING INCOME — — 163,132 109,571 — 272,703 Equity in earnings of equity investees — — 56,484 — — 56,484 Equity in earnings of subsidiaries 327,257 — 96,263 — (423,520 ) — Interest expense, net (222,232 ) — 12,211 (9,419 ) — (219,440 ) Other expense (9,026 ) — — — — (9,026 ) Income before income taxes 95,999 — 328,090 100,152 (423,520 ) 100,721 Income tax expense — — (649 ) (6 ) — (655 ) NET INCOME 95,999 — 327,441 100,146 (423,520 ) 100,066 Net income attributable to noncontrolling interests — — — (1,834 ) — (1,834 ) Net income attributable to redeemable noncontrolling interests — — — (2,233 ) — (2,233 ) NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 95,999 $ — $ 327,441 $ 96,079 $ (423,520 ) $ 95,999 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (74,467 ) — — — — (74,467 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 21,532 $ — $ 327,441 $ 96,079 $ (423,520 ) $ 21,532 Condensed Consolidating Statement of Operations Year Ended December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 284,544 $ — $ — $ 284,544 Sodium minerals and sulfur services — — 333,495 856,221 (15,282 ) 1,174,434 Marine transportation — — 219,937 — — 219,937 Onshore facilities and transportation — — 1,214,235 19,620 — 1,233,855 Total revenues — — 2,052,211 875,841 (15,282 ) 2,912,770 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 1,125,528 1,202 — 1,126,730 Marine transportation operating costs — — 172,527 — — 172,527 Sodium minerals and sulfur services operating costs — — 259,573 668,200 (15,282 ) 912,491 Offshore pipeline transportation operating costs — — 64,272 2,396 — 66,668 General and administrative — — 65,481 1,417 — 66,898 Depreciation, depletion and amortization — — 249,820 63,370 — 313,190 Gain on sale of assets — — (42,264 ) — — (42,264 ) Impairment expense — — 100,093 26,189 — 126,282 Total costs and expenses — — 1,995,030 762,774 (15,282 ) 2,742,522 OPERATING INCOME — — 57,181 113,067 — 170,248 Equity in earnings of equity investees — — 43,626 — — 43,626 Equity in earnings of subsidiaries 219,615 — 107,684 — (327,299 ) — Interest expense, net (230,713 ) — 13,027 (11,505 ) — (229,191 ) Other income 5,023 — — — — 5,023 Income before income taxes (6,075 ) — 221,518 101,562 (327,299 ) (10,294 ) Income tax expense — — (1,727 ) 229 — (1,498 ) NET INCOME (LOSS) (6,075 ) — 219,791 101,791 (327,299 ) (11,792 ) Net loss attributable to noncontrolling interests — — — 5,717 — 5,717 NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ (6,075 ) $ — $ 219,791 $ 107,508 $ (327,299 ) $ (6,075 ) Less: Accumulated distributions attributable to Class A Convertible Preferred Units (69,801 ) — — — — (69,801 ) NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS $ (75,876 ) $ — $ 219,791 $ 107,508 $ (327,299 ) $ (75,876 ) Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 318,239 $ — $ — $ 318,239 Sodium minerals and sulfur services — — 185,852 286,263 (9,493 ) 462,622 Marine transportation — — 205,287 — — 205,287 Onshore facilities and transportation — — 1,023,293 18,936 — 1,042,229 Total revenues — — 1,732,671 305,199 (9,493 ) 2,028,377 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 967,558 1,089 — 968,647 Marine transportation operating costs — — 154,606 — — 154,606 Sodium minerals and sulfur services operating costs — — 117,224 226,187 (9,493 ) 333,918 Offshore pipeline transportation operating costs — — 69,225 2,840 — 72,065 General and administrative — — 65,862 559 — 66,421 Depreciation and amortization — — 232,303 20,177 — 252,480 Gain on sale of assets — — (40,311 ) — — (40,311 ) Total costs and expenses — — 1,566,467 250,852 (9,493 ) 1,807,826 OPERATING INCOME — — 166,204 54,347 — 220,551 Equity in earnings of equity investees — — 51,046 — — 51,046 Equity in earnings of subsidiaries 276,341 — 41,494 — (317,835 ) — Interest expense, net (176,979 ) — 13,825 (13,608 ) — (176,762 ) Other expense (16,715 ) — — — — (16,715 ) Income before income taxes 82,647 — 272,569 40,739 (317,835 ) 78,120 Income tax benefit — — 3,928 31 — 3,959 NET INCOME $ 82,647 $ — $ 276,497 $ 40,770 $ (317,835 ) $ 82,079 Net loss attributable to noncontrolling interest $ — $ — $ — $ 568 $ — 568 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 82,647 $ — $ 276,497 $ 41,338 $ (317,835 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ (21,995 ) $ — $ — $ — $ — (21,995 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 60,652 $ — $ 276,497 $ 41,338 $ (317,835 ) $ 60,652 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 101,385 $ — $ 585,788 $ 82,070 $ (386,956 ) $ 382,287 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (80,141 ) (83,107 ) — (163,248 ) Cash distributions received from equity investees - return of investment — — 21,250 — — 21,250 Investments in equity investees — — — — — — Intercompany transfers 222,595 — — — (222,595 ) — Repayments on loan to non-guarantor subsidiary — — 8,281 — (8,281 ) — Proceeds from asset sales — — 1,187 — — 1,187 Net cash provided by (used in) provided by investing activities 222,595 — (49,423 ) (83,107 ) (230,876 ) (140,811 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 815,100 — — — — 815,100 Repayments on senior secured credit facility (825,900 ) — — — — (825,900 ) Proceeds from issuance of preferred units, net — — — 122,900 — 122,900 Intercompany transfers — — (220,897 ) (1,697 ) 222,594 — Distributions to partners/owners (269,674 ) — (269,674 ) (94,375 ) 364,049 (269,674 ) Distributions to preferred unitholders (43,506 ) — (43,506 ) — 43,506 (43,506 ) Contributions from noncontrolling interest — — — 5,652 — 5,652 Other, net — — 57 12,317 (12,317 ) 57 Net cash provided by (used in) financing activities (323,980 ) — (534,020 ) 44,797 617,832 (195,371 ) Net increase in cash and cash equivalents and restricted cash — — 2,345 43,760 — 46,105 Cash and cash equivalents and restricted cash at beginning of period 6 — 4,924 5,370 — 10,300 Cash and cash equivalents and restricted cash at end of period $ 6 $ — $ 7,269 $ 49,130 $ — $ 56,405 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 28,784 $ — $ 514,096 $ 207,870 $ (360,711 ) $ 390,039 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (114,887 ) (80,480 ) — (195,367 ) Cash distributions received from equity investees - return of investment — — 28,979 — — 28,979 Investments in equity investees — — (3,018 ) — — (3,018 ) Intercompany transfers 503,144 — — — (503,144 ) — Repayments on loan to non-guarantor subsidiary — — 7,484 — (7,484 ) — Proceeds from assets sales — — 310,099 — — 310,099 Net cash (used in) provided by investing activities 503,144 — 228,657 (80,480 ) (510,628 ) 140,693 CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 980,700 — — — — 980,700 Repayments on senior secured credit facility (1,109,800 ) — — — — (1,109,800 ) Repayment of senior unsecured notes (145,170 ) — — — — (145,170 ) Debt issuance costs (242 ) — — — — (242 ) Intercompany transfers — — (485,506 ) (17,638 ) 503,144 — Distributions to partners/owners (257,416 ) — (257,416 ) (123,900 ) 381,316 (257,416 ) Contributions from noncontrolling interest — — — 2,592 — 2,592 Other, net — — (137 ) 13,121 (13,121 ) (137 ) Net cash provided by (used in) financing activities (531,928 ) — (743,059 ) (125,825 ) 871,339 (529,473 ) Net increase in cash and cash equivalents — — (306 ) 1,565 — 1,259 Cash and cash equivalents at beginning of period 6 — 5,230 3,805 — 9,041 Cash and cash equivalents at end of period $ 6 $ — $ 4,924 $ 5,370 $ — $ 10,300 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 162,980 $ — $ 448,873 $ 30,467 $ (318,764 ) $ 323,556 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (236,151 ) (14,442 ) — (250,593 ) Cash distributions received from equity investees - return of investment — — 35,582 — — 35,582 Investments in equity investees (140,513 ) — (4,647 ) — 140,513 (4,647 ) Acquisitions — — (759 ) (1,325,000 ) — (1,325,759 ) Intercompany transfers (1,157,781 ) — (1,325,000 ) — 2,482,781 — Repayments on loan to non-guarantor subsidiary — — 6,764 — (6,764 ) — Contributions in aid of construction costs — — 124 — — 124 Proceeds from asset sales — — 85,722 — — 85,722 Net cash (used in) provided by investing activities (1,298,294 ) — (1,438,365 ) (1,339,442 ) 2,616,530 (1,459,571 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,458,700 — — — — 1,458,700 Repayments on senior secured credit facility (1,637,700 ) — — — — (1,637,700 ) Proceeds from issuance of senior unsecured notes 1,000,000 — — — — 1,000,000 Proceeds from issuance of Series A convertible preferred 726,419 — — — — 726,419 Repayment of senior secured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Distribution to partners/owners (321,875 ) — (321,875 ) (17,500 ) 339,375 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Intercompany transfers — — 1,169,781 1,313,000 (2,482,781 ) — Other, net — — (57 ) 13,847 (13,847 ) (57 ) Net cash provided by (used in) financing activities 1,135,314 — 988,362 1,312,117 (2,297,766 ) 1,138,027 Net increase in cash and cash equivalents — — (1,130 ) 3,142 — 2,012 Cash and cash equivalents at beginning of period 6 — 6,360 663 — 7,029 Cash and cash equivalents at end of period $ 6 $ — $ 5,230 $ 3,805 $ — $ 9,041

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 16, 2020, we issued $750 million in aggregate principal amount of our 7.75% senior unsecured notes due February 15, 2028 (the “2028 Notes”). Interest payments are due February 1 and August 1 of each year with the initial interest payment due on August 1, 2020. That issuance generated net proceeds of $738.9 million net of issuance costs incurred. Our 2028 Notes mature on February 15, 2028. The net proceeds were used to purchase $554.8 million of the 6.75%

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Consolidation and Presentation	Basis of Consolidation and Presentation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2019 , 2018 and 2017 . All intercompany balances and transactions have been eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries. 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.
Joint Ventures	Joint Ventures We participate in several joint ventures, including, in our offshore pipeline transportation segment, a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29%
Use of Estimates	Use of Estimates The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates.
Cash, Cash Equivalents and Restricted Cash	Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. Restricted Cash Our restricted cash balance represents cash held to be used for purposes of our Granger expansion project, as well as a minimum working capital balance we are required to maintain at our unrestricted subsidiary level under contractual agreement and is classified as current on our Consolidated Balance Sheets ( Note 12
Accounts Receivable	Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.
Inventories	Inventories Our inventories are valued at the lower of cost and net realizable value. With the exception of our Alkali Business, cost is determined principally under the average cost method within specific inventory pools. Within our Alkali Business, the cost of inventories are determined using the FIFO, except for materials and supplies which are recorded at average cost, and raw materials which are recorded at standard cost, which approximates actual cost.
Fixed Assets and Mineral Leaseholds	Fixed Assets and Mineral Leaseholds Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 40 years for pipelines and related assets, 20 to 30 years for marine vessels, 3 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 20 years for buildings and improvements, office equipment, furniture and fixtures and other equipment. Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost. Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, the costs incurred to develop such property through the commencement of production are capitalized.
Deferred Charges on Marine Transportation Assets	Deferred Charges on Marine Transportation Assets Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last.
Asset Retirement Obligations	Asset Retirement Obligations Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO 2
Leases, lessee	Lease Accounting
Leases, lessor	Lease Accounting
Intangible and Other Assets	Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight line basis. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with our credit facilities and their related amendments have historically been capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Certain of our capitalized debt issuance costs related to our respective issuances of notes are classified as reductions in long-term debt.
Goodwill	Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. We may also elect to exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. If the calculated fair value of the reporting unit exceeds its carrying value including associated goodwill amounts, the goodwill is considered to be unimpaired and no
Environmental Liabilities	Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
Equity-Based Compensation	Equity-Based Compensation
Revenue Recognition	Revenue Recognition 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 December 31, 2019. However, ASC 606 provides 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. 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 simultaneously 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. Certain of our contracts include a single performance obligation to stand ready, on a 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 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, our performance obligation 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 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. The consideration we receive 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 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 allow for us to make volumetric deductions 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 in the transaction price on a net basis. The net oil recorded is valued at the lower of cost or net realizable value using the market price of crude oil during the month the product was transported. 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 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. Our performance obligation consists of 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 the 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 treating 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 at a 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 that we 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.
Cost of Sales and Operating Expenses	Cost of Sales and Operating Expenses Onshore facilities and transportation operating and product costs include the cost to acquire the product and the associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and other vessels, including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein. When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as onshore facilities and transportation revenues. Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often rebillable and passed through to the customer. The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda. Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines.
Income Taxes	Income Taxes We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner. Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings.
Fair Value of Current Assets and Current Liabilities	Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature.
Pension Benefits	Pension benefits We sponsor a defined benefit plan for employees of our Alkali Business. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income (loss).
Business Acquisitions	Business Acquisitions
Recent and Proposed Accounting Pronouncements	Recent and Proposed Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. The standard requires varying transition methods for the different categories of amendments. We have performed an assessment which consisted of reviewing current and historical information pertaining to our trade accounts receivable and existing contract assets and we anticipate no material impact to our consolidated financial statements as of the adoption date. 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. Refer to Note 3 for further details. We have adopted guidance under ASC Topic 842, Lease Accounting ("ASC 842"), as of January 1, 2019 utilizing the modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to easements, separation of lease components, and the package of practical expedients, which among other things, allows us to carry over previous lease conclusions reached under ASC 840. As a result of adopting the new lease standard, we recorded an operating lease right of use asset of approximately $209 million with a corresponding lease liability as of the transition date. Refer to Note 4 for further details. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance 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 $15.3 million from operating cash flows to investing cash flows for the year ended December 31, 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 year ended December 31, 2018.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue Recognition [Abstract]
Schedule of Disaggregation of Revenue	The following table reflects the disaggregation of our revenues by major category for the years ended December 31, 2019 and December 31, 2018, respectively: Year Ended December 31, 2019 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated Fee-based revenues $ 160,431 $ — $ 318,116 $ 235,645 $ 714,192 Product Sales 660,641 1,023,667 — — 1,684,308 Refinery Services — 82,320 — — 82,320 $ 821,072 $ 1,105,987 $ 318,116 $ 235,645 $ 2,480,820 Year Ended December 31, 2018 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated Fee-based revenues $ 156,266 $ — $ 284,544 $ 219,937 $ 660,747 Product Sales 1,077,589 1,071,634 — — 2,149,223 Refinery Services — 102,800 — — 102,800 $ 1,233,855 $ 1,174,434 $ 284,544 $ 219,937 $ 2,912,770
Schedule of Contract Asset and Liabilities Balances Activity	The table below depicts our contract asset and liability balances at December 31, 2019 and December 31, 2018: Contract Assets Contract Assets Contract Liabilities Contract Liabilities Current Non-Current Current Non-Current Balance at December 31, 2018 $ — $ 72,241 $ — $ 26,271 Balance at December 31, 2019 21,912 54,232 2,896 23,170
Schedule of Revenue Expected to be Recognized in Future Periods	The following chart depicts how we expect to recognize revenues for future periods related to these contracts: Offshore Pipeline Transportation Onshore Facilities and Transportation 2020 $ 75,021 $ 57,615 2021 58,623 20,269 2022 69,134 4,283 2023 58,540 — 2024 52,812 — Thereafter 154,899 — Total $ 469,029 $ 82,167

Lease Accounting (Tables)

Lease Accounting (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of Major Categories of Operating Lease Portfolio	Our lease portfolio consists of operating leases within three major categories: Leases Classification Financial Statement Caption December 31, January 1, Assets Transportation Equipment Right of Use Assets, net $ 98,588 $ 117,727 Office Space & Equipment Right of Use Assets, net 11,085 14,194 Facilities and Equipment Right of Use Assets, net 67,398 77,008 Total Right of Use Assets, net $ 177,071 $ 208,929 Liabilities Current Accrued liabilities 28,406 33,016 Non-Current Other long-term liabilities 144,910 171,348 Total Lease Liability $ 173,316 $ 204,364
Schedule of Maturity of Lease Liabilities	The maturities of our operating lease liabilities as of December 31, 2019 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheet: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2020 $ 26,355 $ 4,119 $ 9,309 $ 39,783 2021 20,282 3,163 6,696 30,141 2022 18,022 2,453 5,383 25,858 2023 17,160 678 5,325 23,163 2024 16,355 689 4,801 21,845 Thereafter 27,163 1,723 123,897 152,783 Total Lease Payments 125,337 12,825 155,411 293,573 Less: Interest (23,428 ) (1,619 ) (95,210 ) (120,257 ) Present value of operating lease liabilities $ 101,909 $ 11,206 $ 60,201 $ 173,316
Schedule of Lease Term and Discount Rates	The following table presents the weighted average remaining term and discount rate related to our right of use assets: Lease Term and Discount Rate December 31, Weighted-average remaining lease term 12.53 years Weighted-average discount rate 7.61% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Cash Flows Information December 31, Cash paid for amounts included in the measurement of lease liabilities $ 44,046 Leased assets obtained in exchange for new operating lease liabilities 198,389
Schedule of Fixed Operating Lease Payments to be Received by Lessor Arrangement	The following table details the fixed lease payments we will receive for our lessor arrangements as of December 31, 2019 : Operating Leases Direct Financing Lease Maturity of Lessor Receipts Marine Transportation Onshore Facilities and Transportation Onshore Facilities and Transportation 2020 $ 20,128 $ 1,200 $ 20,668 2021 — 1,200 20,668 2022 — 1,200 20,668 2023 — 1,200 20,668 2024 — 1,200 20,668 Thereafter — 4,100 72,336 Total Lease Receipts 20,128 10,100 175,676 Less: Interest — — (58,680 ) Total Net Lease Receipts $ 20,128 $ 10,100 $ 116,996
Schedule of Fixed Direct Lease Payments to be Received by Lessor Arrangement	The following table details the fixed lease payments we will receive for our lessor arrangements as of December 31, 2019 : Operating Leases Direct Financing Lease Maturity of Lessor Receipts Marine Transportation Onshore Facilities and Transportation Onshore Facilities and Transportation 2020 $ 20,128 $ 1,200 $ 20,668 2021 — 1,200 20,668 2022 — 1,200 20,668 2023 — 1,200 20,668 2024 — 1,200 20,668 Thereafter — 4,100 72,336 Total Lease Receipts 20,128 10,100 175,676 Less: Interest — — (58,680 ) Total Net Lease Receipts $ 20,128 $ 10,100 $ 116,996

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of Purchase Price Allocation	The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Accounts receivable $ 138,258 Inventories 34,929 Other current assets 13,254 Fixed assets 663,217 Mineral leaseholds 566,019 Intangible assets 800 Other assets 3,612 Accounts payable (44,547 ) Accrued Liabilities (36,884 ) Other long-term liabilities (13,658 ) Total Purchase Price $ 1,325,000
Schedule of Selected Financial Information	The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Year Ended December 31 2017 Revenues $ 277,011 Net income 42,014
Schedule of Pro Forma Financial Information	The dilutive effect of our Class A Convertible Preferred Units is calculated using the if-converted method. Year Ended December 31 2017 Pro forma consolidated financial operating results: Revenues $ 2,549,438 Net Income Attributable to Genesis Energy, L.P. 108,392 Net Income Available to Common Unitholders 42,768 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 Pro forma net income per common unit, basic and dilutive $ 0.35

Receivables (Tables)

Receivables (Tables)	12 Months Ended
	Dec. 31, 2019
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Schedule of Trade Accounts Receivables Net	Accounts receivable – trade, net consisted of the following: December 31, 2019 2018 Accounts receivable - trade $ 418,064 $ 330,855 Allowance for doubtful accounts (1,062 ) (7,393 ) Accounts receivable - trade, net $ 417,002 $ 323,462
Schedule of Allowance For Doubtful Accounts	The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2019 2018 2017 Balance at beginning of period $ 7,393 $ 8,468 $ 6,505 Charged to costs and expenses, net of recoveries (5,572 ) 31 2,001 Amounts written off (759 ) (1,106 ) (38 ) Balance at end of period $ 1,062 $ 7,393 $ 8,468

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Major Components of Inventories	The major components of inventories were as follows: December 31, 2019 2018 Petroleum products $ 2,721 $ 12,203 Crude oil 5,271 8,379 Caustic soda 5,965 10,372 NaHS 10,845 12,400 Raw materials - Alkali Operations 6,238 5,952 Work-in-process - Alkali Operations 8,579 2,322 Finished goods, net - Alkali Operations 14,168 11,402 Materials and supplies, net - Alkali Operations 11,350 10,490 Other — 11 Total $ 65,137 $ 73,531

Fixed Assets and Asset Retire_2

Fixed Assets and Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Fixed Assets And Asset Retirement Obligations [Abstract]
Schedule of Fixed Assets	Fixed assets consisted of the following: December 31, 2019 2018 Crude oil pipelines and natural gas pipelines and related assets $ 2,891,489 $ 2,918,285 Alkali facilities, machinery, and equipment 591,547 533,924 Onshore facilities, machinery, and equipment 640,376 639,023 Transportation equipment 19,864 20,102 Marine vessels 979,171 951,597 Land, buildings and improvements 238,451 222,242 Office equipment, furniture and fixtures 22,645 20,505 Construction in progress 115,162 94,025 Other 41,891 41,155 Fixed assets, at cost 5,540,596 5,440,858 Less: Accumulated depreciation (1,246,121 ) (1,023,825 ) Net fixed assets $ 4,294,475 $ 4,417,033
Schedule of Mineral Leaseholds	Mineral Leaseholds Our Mineral Leaseholds, relating to our acquired Alkali Business, consist of the following: December 31, December 31, Mineral leaseholds $ 566,019 $ 566,019 Less: Accumulated depletion (10,194 ) (5,538 ) Mineral leaseholds, net $ 555,825 $ 560,481
Schedule of Change in Asset Retirement Obligation	A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2017 $ 198,187 Accretion expense 10,509 Revisions in timing and estimated costs of AROs 44,319 Settlements (13,150 ) December 31, 2018 239,865 Accretion expense 9,402 Revisions in timing and estimated costs of AROs (20,529 ) Settlements (53,657 ) December 31, 2019 $ 175,081
Schedule of Forecast or Accretion Expense to Asset Retirement Obligations	With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated: 2020 $ 8,860 2021 $ 8,939 2022 $ 9,417 2023 $ 10,081 2024 $ 10,792

Equity Investees (Tables)

Equity Investees (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Consolidated Financial Statements Related To Equity Investees	The following table presents information included in our Consolidated Financial Statements related to our equity investees. Year Ended December 31, 2019 2018 2017 Genesis’ share of operating earnings $ 71,975 $ 59,255 $ 66,814 Amortization of differences attributable to Genesis' carrying value of equity investments (15,491 ) (15,629 ) (15,768 ) Net equity in earnings $ 56,484 $ 43,626 $ 51,046 Distributions received $ 77,331 $ 71,714 $ 82,898
Schedule of Balance Sheet Information For Equity Investees	The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis): December 31, 2019 2018 BALANCE SHEET DATA: Assets Current assets $ 44,129 $ 34,005 Fixed assets, net 321,752 346,864 Other assets 16,739 15,469 Total assets $ 382,620 $ 396,338 Liabilities and equity Current liabilities $ 20,081 $ 18,897 Other liabilities 252,331 250,742 Equity 110,208 126,699 Total liabilities and equity $ 382,620 $ 396,338
Schedule of Operations For Equity Investees	Year Ended December 31, 2019 2018 2017 INCOME STATEMENT DATA: Revenues $ 209,674 $ 180,056 $ 191,078 Operating Income $ 155,920 $ 129,160 $ 139,604 Net Income $ 139,436 $ 115,669 $ 134,479

Intangible Assets, Goodwill a_2

Intangible Assets, Goodwill and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	The following table reflects the components of intangible assets being amortized at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Intangible associated with lease (1) 15 — — — 13,260 5,407 7,853 Marine contract intangibles 5 27,800 23,033 4,767 27,800 17,593 10,207 Offshore pipeline contract intangibles 19 158,101 36,752 121,349 158,101 28,431 129,670 Other 9 34,291 21,480 12,811 31,747 16,875 14,872 Total $ 220,192 $ 81,265 $ 138,927 $ 230,908 $ 68,306 $ 162,602 (1) Intangible assets associated with a lease in our onshore facilities & transportation segment are now classified as part of our Right or Use Assets, net as part of our adoption of ASC 842 as of January 1, 2019 ( Note 4 ).
Schedule of Estimated Amortization Expense	The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2020 2021 2022 2023 2024 Marine contract intangibles 4,538 37 35 34 33 Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 2,453 2,168 2,010 1,621 1,421 Total $ 15,312 $ 10,526 $ 10,366 $ 9,976 $ 9,775
Schedule of Other Assets	Other assets consisted of the following: December 31, 2019 2018 CO 2 volumetric production payments, net of amortization $ — $ 890 Deferred marine charges, net (1) 24,098 28,175 Contract assets (2) 54,232 72,241 Other deferred costs 15,755 20,401 Other assets, net of amortization $ 94,085 $ 121,707 (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 ) (2) See Revenue Recognition ( Note 3 ) for discussion on the circumstances that result in the recognition of contract assets.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Obligations Under Debt Arrangements	At December 31, 2019 and 2018 , our obligations under debt arrangements consisted of the following: December 31, 2019 December 31, 2018 Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Senior secured credit facility $ 959,300 $ — $ 959,300 $ 970,100 $ — $ 970,100 6.750% senior unsecured notes 750,000 9,349 740,651 750,000 12,763 737,237 6.000% senior unsecured notes 400,000 3,557 396,443 400,000 4,624 395,376 5.625% senior unsecured notes 350,000 3,923 346,077 350,000 4,820 345,180 6.500% senior unsecured notes 550,000 7,020 542,980 550,000 8,241 541,759 6.250% senior unsecured notes 450,000 $ 6,214 443,786 450,000 7,189 442,811 Total long-term debt $ 3,459,300 $ 30,063 $ 3,429,237 $ 3,470,100 $ 37,637 $ 3,432,463 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Consolidated Balance Sheet) were $7.6 million and $10.8 million as of December 31, 2019 and December 31, 2018, respectively.
Schedule of Summary of Applicable Redemption Periods	A summary of the applicable redemption periods is provided in the table below. 2022 Notes (1) 2023 Notes 2024 Notes 2025 Notes 2026 Notes Redemption right beginning on August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 (1) Refer to Note 26 for discussion surrounding our tender and redemption of our 2022 Notes, along with the issuance of our 2028 Notes during the first quarter of 2020.

Partners' Capital, Mezzanine _2

Partners' Capital, Mezzanine Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of Paid Distributions	We paid common unitholders distributions in 2020 , 2019 and 2018 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2017 4th Quarter February 14, 2018 $ 0.5100 $ 62,515 2018 1st Quarter May 15, 2018 $ 0.5200 $ 63,741 2nd Quarter August 14, 2018 $ 0.5300 $ 64,967 3rd Quarter November 14, 2018 $ 0.5400 $ 66,193 4th Quarter February 14, 2019 $ 0.5500 $ 67,419 2019 1st Quarter May 15, 2019 $ 0.5500 $ 67,419 2nd Quarter August 14, 2019 $ 0.5500 $ 67,419 3rd Quarter November 14, 2019 $ 0.5500 $ 67,419 4th Quarter February 14, 2020 $ 0.5500 $ 67,419 We paid the following cash distributions to our preferred unitholders: Distribution For Date Paid Per Unit Total 2019 1 st Quarter May 15, 2019 $ 0.2458 $ 6,138 2 nd Quarter August 14, 2019 $ 0.7374 $ 18,684 3 rd Quarter November 14, 2019 $ 0.7374 $ 18,684 4 th Quarter February 14, 2020 $ 0.7374 $ 18,684
Schedule of New Common Units Issued to the Public For Cash	The new common units issued in 2017 to the public for cash were as follows: Period Purchaser of Common Units Units Gross Unit Price Issuance Value Costs Net Proceeds March 2017 Public 4,600 $ 30.65 $ 140,990 $ (477 ) $ 140,513
Schedule of Initial Measurement of Class A Convertible Preferred Units	As discussed above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long term liabilities on the Consolidated Balance Sheet as described below (as of the inception date): September 1, 2017 Transaction price, gross $ 750,000 Transaction cost to other third parties (23,581 ) Transaction price, net 726,419 Allocation of Net Transaction Price Preferred Units, net 691,969 Preferred Distribution Rate Reset Election ( Note 19 ) 34,450 $ 726,419
Schedule of Paid in Kind Distributions	Preferred unit distributions are recognized on the date in which they are declared. Paid in kind distributions were declared and issued as follows: Distribution Declared Date Issued Number of Units Total Amount 2017 November 2017 November 14, 2018 162,234 $ 5,469 2018 January 2018 February 14, 2018 490,252 $ 16,526 April 2018 May 15, 2018 500,967 $ 16,888 July 2018 August 14, 2018 511,934 $ 17,257 October 2018 November 14, 2018 523,132 $ 17,635 2019 January 2019 February 14, 2019 534,576 $ 18,021 April 2019 May 15, 2019 364,180 $ 12,277
Schedule of Changes in Class A Convertible Preferred Units	The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2019: Class A Convertible Preferred Units Units $ December 31, 2016 — $ — Issuance of Preferred Units, net 22,249,494 726,419 Allocation to Preferred Distribution Rate Reset Election ( Note 19 ) — (34,450 ) Distributions paid-in-kind 162,234 5,469 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (287 ) Balance as of December 31, 2017 22,411,728 $ 697,151 Distributions paid-in-kind 2,026,294 68,306 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (3,991 ) Balance as of December 31, 2018 24,438,022 $ 761,466 Distributions paid-in-kind 898,756 30,298 Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election ( Note 19 ) — (1,649 ) Balance as of December 31, 2019 25,336,778 $ 790,115
Schedule of Changes in Redeemable Noncontrolling Interest	The following table shows the change in our redeemable noncontrolling interests from initial measurement at September 23, 2019 to December 31, 2019 : Year Ended December 31 2019 Issuance of Preferred Units $ 55,000 Issuance costs (5,600 ) Balance as of September 23, 2019 49,400 Issuance of preferred units, net of issuance costs 73,500 Distribution paid-in-kind 1,778 Redemption accretion 455 Balance as of December 31, 2019 $ 125,133

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2019
Net Income per Common Unit [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts): Year Ended December 31 2019 2018 2017 Net Income (Loss) Attributable to Genesis Energy L.P. $ 95,999 $ (6,075 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (74,467 ) (69,801 ) (21,995 ) Net Income (Loss) Available to Common Unitholders $ 21,532 $ (75,876 ) $ 60,652 Weighted Average Outstanding Units 122,579 122,579 121,546 Basic and Diluted Net Income (Loss) per Common Unit $ 0.18 $ (0.62 ) $ 0.50

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total Year Ended December 31, 2019 Segment Margin (a) $ 320,023 $ 223,908 $ 111,412 $ 57,919 $ 713,262 Capital expenditures (b) $ 17,809 $ 107,837 $ 6,576 $ 40,820 $ 173,042 Revenues: External customers $ 318,116 $ 1,113,623 $ 824,148 $ 224,933 $ 2,480,820 Intersegment (c) — (7,636 ) (3,076 ) 10,712 $ — Total revenues of reportable segments $ 318,116 $ 1,105,987 $ 821,072 $ 235,645 $ 2,480,820 Year Ended December 31, 2018 Segment Margin (a) $ 285,014 $ 260,488 $ 119,918 $ 47,338 $ 712,758 Capital expenditures (b) $ 4,703 $ 74,712 $ 51,110 $ 30,868 $ 161,393 Revenues: External customers $ 284,544 $ 1,181,578 $ 1,240,382 $ 206,266 $ 2,912,770 Intersegment (c) — (7,144 ) (6,527 ) 13,671 $ — Total revenues of reportable segments $ 284,544 $ 1,174,434 $ 1,233,855 $ 219,937 $ 2,912,770 Year Ended December 31, 2017 Segment Margin (a) $ 317,540 $ 130,333 $ 96,376 $ 50,294 $ 594,543 Capital expenditures (b) $ 8,815 $ 1,354,469 $ 149,123 $ 68,414 $ 1,580,821 Revenues: External customers $ 319,455 $ 470,789 $ 1,044,083 $ 194,050 $ 2,028,377 Intersegment (c) (1,216 ) (8,167 ) (1,854 ) 11,237 $ — Total revenues of reportable segments $ 318,239 $ 462,622 $ 1,042,229 $ 205,287 $ 2,028,377 Total assets by reportable segment were as follows: December 31, 2019 December 31, 2018 December 31, 2017 Offshore pipeline transportation $ 2,306,946 $ 2,359,013 $ 2,486,803 Sodium minerals and sulfur services 2,019,905 1,844,845 1,848,188 Onshore facilities and transportation 1,457,190 1,431,910 1,927,976 Marine transportation 772,383 800,243 824,777 Other assets 41,217 43,060 49,737 Total consolidated assets $ 6,597,641 $ 6,479,071 $ 7,137,481 (a) A reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P. for each year 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. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. (c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
Schedule of Reconciliation of Segment Margin To (Loss) Income Before Income Taxes	Reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P.: Year Ended December 31 2019 2018 2017 Total Segment Margin $ 713,262 $ 712,758 $ 594,543 Corporate general and administrative expenses (52,755 ) (64,683 ) (60,029 ) Depreciation, depletion, amortization and accretion (308,115 ) (317,186 ) (262,021 ) Interest expense (219,440 ) (229,191 ) (176,762 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (20,847 ) (28,088 ) (31,852 ) Non-cash items not included in Segment Margin (14,642 ) 9,698 (14,305 ) Cash payments from direct financing leases in excess of earnings (8,421 ) (7,633 ) (6,921 ) Loss on extinguishment of debt — (3,339 ) (6,242 ) Differences in timing of cash receipts for certain contractual arrangements (2) 8,478 6,629 17,540 Gain on sales of assets — 42,264 40,311 Other, net — — (2,985 ) Non-cash provision for leased items no longer in use 1,367 476 (12,589 ) Income tax (expense) benefit (655 ) (1,498 ) 3,959 Redeemable noncontrolling interest redemption value adjustments (3) (2,233 ) — — Impairment expense — (126,282 ) — Net income (loss) attributable to Genesis Energy, L.P. $ 95,999 $ (6,075 ) $ 82,647 (1) Includes distributions attributable to the period and received during or promptly following such period. (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. (3) Includes distributions paid in kind attributable to the period and accretion on the redemption feature.

Transactions with Related Par_2

Transactions with Related Parties (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Transactions With Related Parties	Transactions with related parties were as follows: Year Ended December 31, 2019 2018 2017 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ — $ 1,233 $ 2,820 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,669 12,557 12,357 Revenues from product sales to ANSAC 367,133 373,606 124,536 Expenses: Amounts paid to our CEO in connection with the use of his aircraft $ 660 $ 660 $ 660 Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2) 975 994 986 Charges for services from ANSAC 4,446 5,284 2,242 (1) We owned a 50% interest in Sandhill Group, LLC which was sold in the third quarter of 2018. (2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. As of December 31, 2019 and 2018 , our receivables from and payables to ANSAC were: December 31 December 31 2019 2018 Receivables: ANSAC $ 68,075 $ 60,594 Payables: ANSAC $ 2,103 $ 815

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Schedule of Net Changes In Components Of Operating Assets And Liabilities	The following table provides information regarding the net changes in components of operating assets and liabilities: Year Ended December 31, 2019 2018 2017 (Increase) decrease in: Accounts receivable $ (80,126 ) $ 130,573 $ (140,948 ) Inventories 7,659 20,963 49,055 Deferred charges 4,093 (5,826 ) (3,622 ) Other current assets (4,874 ) 9,337 (410 ) Increase (decrease) in: Accounts payable 81,915 (130,991 ) 97,569 Accrued liabilities (79,765 ) (26,208 ) 8,512 Net changes in components of operating assets and liabilities $ (71,098 ) $ (2,152 ) $ 10,156

Equity-Based Compensation Pla_2

Equity-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Schedule of Service-Based And Performance-Based Awards	A summary of our phantom unit activity for our service-based and performance-based awards is set forth below: Service-Based Awards Performance-Based Awards Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Unvested at December 31, 2018 195,939 $ 30.40 $ 5,958 378,006 $ 31.09 $ 11,754 Granted 29,606 $ 21.28 630 — $ — — Forfeited (1,098 ) $ 32.43 (36 ) (1,653 ) $ 32.43 (54 ) Settled (76,370 ) $ 31.79 (2,428 ) (213,582 ) $ 30.37 (6,486 ) Unvested at December 31, 2019 148,077 $ 27.85 $ 4,124 162,771 $ 32.02 $ 5,214
Schedule of Equity-Based Compensation Expense	Equity-based compensation expense during the three years ended December 31, 2019 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2019 2018 2017 Onshore facilities and transportation operating costs $ 250 $ 140 $ (1,137 ) Marine transportation operating costs 173 183 (483 ) Sodium minerals and sulfur services operating costs 140 112 (533 ) Offshore pipeline operating costs 269 297 (152 ) General and administrative expenses 1,087 1,239 (2,272 ) Total $ 1,919 $ 1,971 $ (4,577 )

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivatives Entered Into Hedge Inventory or Fixed Price Purchase Commitments	At December 31, 2019 , we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. Sell (Short) Contracts Buy (Long) Contracts Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 19 — Weighted average contract price per bbl $ 58.57 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 79 80 Weighted average contract price per bbl $ 60.25 $ 60.25 Natural gas swaps: Contract volumes (10,000 MMBTU) 503 — Weighted average price differential per MMBTU $ 0.38 — Natural gas futures: Contract volumes (10,000 MMBTU) 92 576 Weighted average contract price per MMBTU $ 2.27 $ 2.60 Crude oil options: Contract volumes (1,000 bbls) 40 18 Weighted average premium received/paid $ 1.03 $ 0.66
Schedule of Accounting Treatment And Classification of Derivative Instruments	The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements. Derivative Instrument Hedged Risk Impact of Unrealized Gains and Losses Consolidated Balance Sheets Consolidated Statements of Operations Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories Excess, if any, over effective portion of hedge is recorded in Onshore facilities and transportation costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged Not qualifying or not designated as hedges under accounting guidance: Commodity hedges consisting of crude oil, heating oil and natural gas futures, forward contracts, swaps and call options Volatility in crude oil, natural gas and petroleum products prices - effect on market value of inventory or purchase commitments Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities Entire amount of change in fair value of derivative is recorded in Onshore facilities and transportation costs - product costs and Sodium minerals and sulfur services - operating costs Preferred Distribution Rate Reset Election This instrument is not related to a risk, but is rather part of a host contract with the issuance of our Preferred Units Derivative is recorded in Other long-term liabilities Entire amount of change in fair value of derivative is recorded in Other income (expense)
Schedule of Fair Value of Derivative Assets And Liabilities	The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2019 and 2018 : Fair Value of Derivative Assets and Liabilities Fair Value Consolidated Balance Sheets Location December 31, 2019 December 31, 2018 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 207 $ 3,431 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (207 ) (1,361 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ 2,070 Natural Gas Swap (undesignated hedge) Current Assets - Other 1,382 1,274 Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 4 $ 469 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (4 ) (44 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ 425 Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (51,515 ) $ (40,840 ) Natural Gas Swap (undesignated hedge) Current Liabilities - Accrued Liabilities — (125 ) Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (2,079 ) $ (1,361 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,064 1,361 Net amount of liabilities presented in the Consolidated Balance Sheets $ (1,015 ) $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (50 ) $ (44 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 50 44 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — (1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other. (2) Refer to Note 12 and Note 20 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.
Schedule of Effect on Consolidated Statements of Operations And Other Comprehensive Income (Loss)	Effect on Operating Results Amount of Gain (Loss) Recognized in Income Year Ended December 31 Consolidated Statements of Operations Location 2019 2018 2017 Commodity derivatives—futures and options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ (786 ) $ (544 ) $ 5,116 Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs (7,790 ) 3,914 (1,314 ) Total commodity derivatives $ (8,576 ) $ 3,370 $ 3,802 Natural Gas Swaps Sodium minerals and sulfur services operating costs 1,941 $ 1,906 $ — Preferred Distribution Rate Reset Election ( Note 20 ) Other Income (Expense) $ (9,026 ) $ 8,360 $ (10,472 )

Fair-Value Measurements (Tables

Fair-Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Placement Of Assets And Liabilities Within The Fair Value Hierarchy Levels	The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 . December 31, 2019 December 31, 2018 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 211 $ 1,382 $ — $ 3,900 $ 1,274 $ — Liabilities $ (2,129 ) $ — $ — $ (1,405 ) $ (125 ) $ — Preferred Distribution Rate Reset Election $ — $ — $ (51,515 ) $ — $ — $ (40,840 )
Schedule of Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3: Balance as of December 31, 2017 $ (45,209 ) Net gain for the period including earnings 8,360 Allocation of Distribution Paid-in-kind (3,991 ) Balance as of December 31, 2018 (40,840 ) Net loss for the period included in earnings (9,026 ) Allocation of Distribution Paid-in-kind (1,649 ) Balance as of December 31, 2019 $ (51,515 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Schedule of Changes in Benefit Obligations, Plan Assets and Funded Status with Amounts Recognized in Consolidated Balance Sheet	The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2019 2018 Change in benefit obligation: Benefit Obligation, beginning of year $ 24,511 $ 22,530 Service Cost 4,351 5,153 Interest Cost 1,340 862 Plan Amendment 6,569 — Actuarial (Gain) Loss 5,981 (3,816 ) Benefits Paid (461 ) (218 ) Benefit Obligation, end of year 42,291 24,511 Change in plan assets: Fair Value of Plan Assets, beginning of year 15,716 13,306 Actual Return (loss) on Plan Assets 4,025 (1,300 ) Employer Contributions 4,771 3,928 Benefits Paid (461 ) (218 ) Fair Value of Plan assets, end of year 24,051 15,716 Funded Status at end of period $ (18,240 ) $ (8,795 ) Amounts recognized in the Consolidated Balance Sheet: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (18,240 ) (8,795 ) Net Liability at end of year $ (18,240 ) $ (8,795 ) Amounts recognized in accumulated other comprehensive income (loss): Prior Service Cost 6,163 — Net actuarial (gain) loss 2,268 (939 ) Amounts recognized in accumulated other comprehensive income ( loss:) $ 8,431 $ (939 )
Schedule of Expected Employer Contributions and Future Benefits Payments	The following employer contributions and benefit payments, which reflect expected future service, are expected to be paid as follows: Employer Contributions Expected 2020 Contributions by Employer $ 5,850 Future Expected Benefit Payments 2020 $ 824 2021 1,112 2022 1,343 2023 1,537 2024 1,714 2025-2029 11,250
Schedule of Components of Net Periodic Costs	The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2019 2018 2017 Service Cost $ 4,351 $ 5,153 $ 1,749 Interest Cost 1,340 862 267 Expected Return on Assets (1,252 ) (973 ) (259 ) Amortization of Prior Service Cost 406 — — Total Net Periodic Benefit Costs (1) $ 4,845 $ 5,042 $ 1,757 (1) On September 1, 2017, we acquired our Alkali Business including the Company's defined benefit plan. The 2017 Net Periodic Benefit Cost represents the period of the year subsequent to our purchase of the Alkali Business resulting in a lower annual cost compared to 2019 and 2018, respectively.
Schedule of Weighted Average Assumptions Used To Determine Benefit Obligation	The Alkali Business pension plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan's management. The committee is responsible for the oversight and management of the plan's investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2019 December 31, 2018 Discount Rate 3.56 % 4.62 % Expected Long-term Rate of Return 6.06 % 6.41 % Rate of Compensation Increase N/A N/A The discount rate used to determine the net periodic cost at the beginning of the period was 4.62% .
Schedule of Pension Plan Asset Allocations	A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2019 2018 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents 1,311 — — $ 1,311 506 — — $ 506 Equity securities 13,192 — — $ 13,192 8,038 — — $ 8,038 Mutual and other exchange traded funds 9,548 — — $ 9,548 7,172 — — $ 7,172 24,051 — — $ 24,051 15,716 — — $ 15,716 December 31, 2019 Target % Actual % Equity securities 41-60% 55 % Fixed income securities and other 40-60% 45 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Income Tax (Benefit) Expense	Our income tax (benefit) expense is as follows: Year Ended December 31, 2019 2018 2017 Current: Federal $ — $ — $ — State 591 810 100 Total current income tax expense $ 591 $ 810 $ 100 Deferred: Federal $ 930 $ 114 $ (5,530 ) State (866 ) 574 1,471 Total deferred income tax expense (benefit) $ 64 $ 688 $ (4,059 ) Total income tax expense (benefit) $ 655 $ 1,498 $ (3,959 )
Schedule of Deferred Tax Assets And Liabilities	Deferred tax assets and liabilities consist of the following: December 31, 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 12,557 $ 11,057 Other 927 434 Total long-term deferred tax asset 13,484 11,491 Valuation allowances (2,172 ) (1,758 ) Total deferred tax assets $ 11,312 $ 9,733 Deferred tax liabilities: Long-term: Fixed assets $ (1,958 ) $ (2,893 ) Intangible assets (20,730 ) (18,209 ) Other (1,264 ) (1,207 ) Total long-term liability (23,952 ) (22,309 ) Total deferred tax liabilities $ (23,952 ) $ (22,309 ) Total net deferred tax liability $ (12,640 ) $ (12,576 )
Schedule of Reconciliation of Federal Statutory Income Tax Rate To Income Before Income Taxes	The reconciliation between the Partnership's effective tax rate on income (loss) from operations and the statutory tax rate is as follows: Year Ended December 31, 2019 2018 2017 Income (loss) from operations before income taxes $ 100,721 $ (10,294 ) $ 78,120 Partnership income not subject to federal income tax (99,832 ) 10,824 (77,704 ) Income subject to federal income taxes $ 889 $ 530 $ 416 Tax expense at federal statutory rate $ 187 $ 111 $ 146 State income taxes, net of federal tax 729 1,285 1,396 Return to provision, federal and state (219 ) (128 ) (163 ) Other (42 ) 230 (68 ) Re-measurement of deferred taxes due to enacted tax rate change — — (5,270 ) Income tax expense (benefit) $ 655 $ 1,498 $ (3,959 ) Effective tax rate on income from operations before income taxes 1 % (15 )% (5 )%

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Schedule of Summarized Unaudited Quarterly Financial Data	The table below summarizes our unaudited quarterly financial data for 2019 and 2018 . 2019 Quarters First Second Third Fourth Revenues from continuing operations $ 620,009 $ 634,785 $ 621,697 $ 604,329 Operating income $ 62,029 $ 86,948 $ 52,787 $ 70,939 Net income $ 15,947 $ 41,652 $ 17,807 $ 24,660 Net loss (income) attributable to noncontrolling interest $ 7 $ (1,532 ) $ 22 $ (331 ) Net income attributable to redeemable noncontrolling interest $ — $ — $ (272 ) $ (1,961 ) Net income attributable to Genesis Energy, L.P. $ 15,954 $ 40,120 $ 17,557 $ 22,368 Basic and diluted net income (loss) per common unit: Net income (loss) per common unit $ (0.02 ) $ 0.17 $ (0.01 ) $ 0.03 Cash distributions per common unit (1) $ 0.5500 $ 0.5500 $ 0.5500 $ 0.5500 2018 Quarters First Second Third Fourth Revenues from continuing operations $ 725,808 $ 752,388 $ 745,278 $ 689,296 Operating income $ 59,081 $ 60,900 $ 46,148 $ 4,119 Net income (loss) $ 7,898 $ 10,871 $ (1,634 ) $ (28,927 ) Net loss attributable to noncontrolling interest $ 136 $ 126 $ 1,311 $ 4,144 Net income (loss) attributable to Genesis Energy, L.P. $ 8,034 $ 10,997 $ (323 ) $ (24,783 ) Basic and diluted net loss per common unit: Net loss per common unit $ (0.07 ) $ (0.05 ) $ (0.15 ) $ (0.35 ) Cash distributions per common unit (1) $ 0.5200 $ 0.5300 $ 0.5400 $ 0.5500 (1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule of Condensed Consolidating Financial Statements	Condensed Consolidating Balance Sheet December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 7,269 $ 21,853 $ — $ 29,128 Restricted cash — — — 27,277 — 27,277 Other current assets 50 — 316,166 220,526 (73 ) 536,669 Total current assets 56 — 323,435 269,656 (73 ) 593,074 Fixed Assets, at cost — — 4,627,696 912,900 — 5,540,596 Less: Accumulated depreciation — — (1,089,246 ) (156,875 ) — (1,246,121 ) Net fixed assets — — 3,538,450 756,025 — 4,294,475 Mineral Leaseholds, net of accumulated depletion — — — 555,825 — 555,825 Goodwill — — 301,959 — — 301,959 Other assets, net of amortization 7,583 — 403,277 109,862 (180,008 ) 340,714 Advances to affiliates 3,039,468 — — 158,798 (3,198,266 ) — Equity investees — — 334,523 — — 334,523 Investments in subsidiaries 2,706,095 — 1,420,664 — (4,126,759 ) — Right of use assets, net — — 83,942 93,129 — 177,071 Total assets $ 5,753,202 $ — $ 6,406,250 $ 1,943,295 $ (7,505,106 ) $ 6,597,641 LIABILITIES AND CAPITAL Current liabilities $ 39,015 $ — $ 253,926 $ 122,673 $ (119 ) $ 415,495 Senior secured credit facility 959,300 — — — — 959,300 Senior unsecured notes, net of debt issuance costs 2,469,937 — — — — 2,469,937 Deferred tax liabilities — — 12,640 — — 12,640 Advances from affiliates — — 3,198,277 — (3,198,277 ) — Other liabilities 51,515 — 245,424 276,789 (179,878 ) 393,850 Total liabilities 3,519,767 — 3,710,267 399,462 (3,378,274 ) 4,251,222 Mezzanine Capital: Class A Convertible Preferred Units 790,115 — — — — 790,115 Redeemable noncontrolling interests — — — 125,133 — 125,133 Partners’ capital, common units 1,443,320 — 2,695,983 1,430,849 (4,126,832 ) 1,443,320 Accumulated other comprehensive income (loss) (1) — — — (8,431 ) — (8,431 ) Noncontrolling interests — — — (3,718 ) — (3,718 ) Total liabilities, mezzanine capital and partners’ capital $ 5,753,202 $ — $ 6,406,250 $ 1,943,295 $ (7,505,106 ) $ 6,597,641 (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. Condensed Consolidating Balance Sheet December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 4,924 $ 5,370 $ — $ 10,300 Other current assets 50 — 229,411 203,683 (165 ) 432,979 Total current assets 56 — 234,335 209,053 (165 ) 443,279 Fixed Assets, at cost — — 4,602,164 838,694 — 5,440,858 Less: Accumulated depreciation — — (926,830 ) (96,995 ) — (1,023,825 ) Net fixed assets — — 3,675,334 741,699 — 4,417,033 Mineral Leaseholds, net of accumulated depletion — — — 560,481 — 560,481 Goodwill — — 301,959 — — 301,959 Other assets, net 10,776 — 435,540 122,538 (167,620 ) 401,234 Advances to affiliates 3,305,568 — — 105,917 (3,411,485 ) — Equity investees — — 355,085 — — 355,085 Investments in subsidiaries 2,648,510 — 1,413,334 — (4,061,844 ) — Total assets $ 5,964,910 $ — $ 6,415,587 $ 1,739,688 $ (7,641,114 ) $ 6,479,071 LIABILITIES AND CAPITAL Current liabilities $ 39,342 $ — $ 177,104 $ 116,498 $ (110 ) $ 332,834 Senior secured credit facility 970,100 — — — — 970,100 Senior unsecured notes, net of debt issuance costs 2,462,363 — — — — 2,462,363 Deferred tax liabilities — — 12,576 — — 12,576 Advances from affiliates — — 3,411,515 — (3,411,515 ) — Other liabilities 40,840 — 174,249 211,590 (167,481 ) 259,198 Total liabilities 3,512,645 — 3,775,444 328,088 (3,579,106 ) 4,037,071 Mezzanine Capital Class A Convertible Preferred Units 761,466 — — — — 761,466 Partners' capital, common units 1,690,799 — 2,640,143 1,421,865 (4,062,008 ) 1,690,799 Accumulated other comprehensive income (loss) (1) — — — 939 — 939 Noncontrolling interests — — — (11,204 ) — (11,204 ) Total liabilities, mezzanine capital and partners’ capital $ 5,964,910 $ — $ 6,415,587 $ 1,739,688 $ (7,641,114 ) $ 6,479,071 (1) The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries. Condensed Consolidating Statement of Operations Year Ended December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 318,116 $ — $ — $ 318,116 Sodium minerals and sulfur services — — 260,675 852,949 (7,637 ) 1,105,987 Marine transportation — — 235,645 — — 235,645 Onshore facilities and transportation — — 802,735 18,337 — 821,072 Total revenues — — 1,617,171 871,286 (7,637 ) 2,480,820 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 713,577 1,327 — 714,904 Marine transportation operating costs — — 178,032 — — 178,032 Sodium minerals and sulfur services operating costs — — 200,845 690,484 (7,637 ) 883,692 Offshore pipeline transportation operating costs — — 68,167 (9,171 ) — 58,996 General and administrative — — 51,191 1,496 — 52,687 Depreciation, depletion and amortization — — 242,227 77,579 — 319,806 Total costs and expenses — — 1,454,039 761,715 (7,637 ) 2,208,117 OPERATING INCOME — — 163,132 109,571 — 272,703 Equity in earnings of equity investees — — 56,484 — — 56,484 Equity in earnings of subsidiaries 327,257 — 96,263 — (423,520 ) — Interest expense, net (222,232 ) — 12,211 (9,419 ) — (219,440 ) Other expense (9,026 ) — — — — (9,026 ) Income before income taxes 95,999 — 328,090 100,152 (423,520 ) 100,721 Income tax expense — — (649 ) (6 ) — (655 ) NET INCOME 95,999 — 327,441 100,146 (423,520 ) 100,066 Net income attributable to noncontrolling interests — — — (1,834 ) — (1,834 ) Net income attributable to redeemable noncontrolling interests — — — (2,233 ) — (2,233 ) NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 95,999 $ — $ 327,441 $ 96,079 $ (423,520 ) $ 95,999 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (74,467 ) — — — — (74,467 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 21,532 $ — $ 327,441 $ 96,079 $ (423,520 ) $ 21,532 Condensed Consolidating Statement of Operations Year Ended December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 284,544 $ — $ — $ 284,544 Sodium minerals and sulfur services — — 333,495 856,221 (15,282 ) 1,174,434 Marine transportation — — 219,937 — — 219,937 Onshore facilities and transportation — — 1,214,235 19,620 — 1,233,855 Total revenues — — 2,052,211 875,841 (15,282 ) 2,912,770 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 1,125,528 1,202 — 1,126,730 Marine transportation operating costs — — 172,527 — — 172,527 Sodium minerals and sulfur services operating costs — — 259,573 668,200 (15,282 ) 912,491 Offshore pipeline transportation operating costs — — 64,272 2,396 — 66,668 General and administrative — — 65,481 1,417 — 66,898 Depreciation, depletion and amortization — — 249,820 63,370 — 313,190 Gain on sale of assets — — (42,264 ) — — (42,264 ) Impairment expense — — 100,093 26,189 — 126,282 Total costs and expenses — — 1,995,030 762,774 (15,282 ) 2,742,522 OPERATING INCOME — — 57,181 113,067 — 170,248 Equity in earnings of equity investees — — 43,626 — — 43,626 Equity in earnings of subsidiaries 219,615 — 107,684 — (327,299 ) — Interest expense, net (230,713 ) — 13,027 (11,505 ) — (229,191 ) Other income 5,023 — — — — 5,023 Income before income taxes (6,075 ) — 221,518 101,562 (327,299 ) (10,294 ) Income tax expense — — (1,727 ) 229 — (1,498 ) NET INCOME (LOSS) (6,075 ) — 219,791 101,791 (327,299 ) (11,792 ) Net loss attributable to noncontrolling interests — — — 5,717 — 5,717 NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ (6,075 ) $ — $ 219,791 $ 107,508 $ (327,299 ) $ (6,075 ) Less: Accumulated distributions attributable to Class A Convertible Preferred Units (69,801 ) — — — — (69,801 ) NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS $ (75,876 ) $ — $ 219,791 $ 107,508 $ (327,299 ) $ (75,876 ) Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation $ — $ — $ 318,239 $ — $ — $ 318,239 Sodium minerals and sulfur services — — 185,852 286,263 (9,493 ) 462,622 Marine transportation — — 205,287 — — 205,287 Onshore facilities and transportation — — 1,023,293 18,936 — 1,042,229 Total revenues — — 1,732,671 305,199 (9,493 ) 2,028,377 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 967,558 1,089 — 968,647 Marine transportation operating costs — — 154,606 — — 154,606 Sodium minerals and sulfur services operating costs — — 117,224 226,187 (9,493 ) 333,918 Offshore pipeline transportation operating costs — — 69,225 2,840 — 72,065 General and administrative — — 65,862 559 — 66,421 Depreciation and amortization — — 232,303 20,177 — 252,480 Gain on sale of assets — — (40,311 ) — — (40,311 ) Total costs and expenses — — 1,566,467 250,852 (9,493 ) 1,807,826 OPERATING INCOME — — 166,204 54,347 — 220,551 Equity in earnings of equity investees — — 51,046 — — 51,046 Equity in earnings of subsidiaries 276,341 — 41,494 — (317,835 ) — Interest expense, net (176,979 ) — 13,825 (13,608 ) — (176,762 ) Other expense (16,715 ) — — — — (16,715 ) Income before income taxes 82,647 — 272,569 40,739 (317,835 ) 78,120 Income tax benefit — — 3,928 31 — 3,959 NET INCOME $ 82,647 $ — $ 276,497 $ 40,770 $ (317,835 ) $ 82,079 Net loss attributable to noncontrolling interest $ — $ — $ — $ 568 $ — 568 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 82,647 $ — $ 276,497 $ 41,338 $ (317,835 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ (21,995 ) $ — $ — $ — $ — (21,995 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 60,652 $ — $ 276,497 $ 41,338 $ (317,835 ) $ 60,652 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 101,385 $ — $ 585,788 $ 82,070 $ (386,956 ) $ 382,287 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (80,141 ) (83,107 ) — (163,248 ) Cash distributions received from equity investees - return of investment — — 21,250 — — 21,250 Investments in equity investees — — — — — — Intercompany transfers 222,595 — — — (222,595 ) — Repayments on loan to non-guarantor subsidiary — — 8,281 — (8,281 ) — Proceeds from asset sales — — 1,187 — — 1,187 Net cash provided by (used in) provided by investing activities 222,595 — (49,423 ) (83,107 ) (230,876 ) (140,811 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 815,100 — — — — 815,100 Repayments on senior secured credit facility (825,900 ) — — — — (825,900 ) Proceeds from issuance of preferred units, net — — — 122,900 — 122,900 Intercompany transfers — — (220,897 ) (1,697 ) 222,594 — Distributions to partners/owners (269,674 ) — (269,674 ) (94,375 ) 364,049 (269,674 ) Distributions to preferred unitholders (43,506 ) — (43,506 ) — 43,506 (43,506 ) Contributions from noncontrolling interest — — — 5,652 — 5,652 Other, net — — 57 12,317 (12,317 ) 57 Net cash provided by (used in) financing activities (323,980 ) — (534,020 ) 44,797 617,832 (195,371 ) Net increase in cash and cash equivalents and restricted cash — — 2,345 43,760 — 46,105 Cash and cash equivalents and restricted cash at beginning of period 6 — 4,924 5,370 — 10,300 Cash and cash equivalents and restricted cash at end of period $ 6 $ — $ 7,269 $ 49,130 $ — $ 56,405 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 28,784 $ — $ 514,096 $ 207,870 $ (360,711 ) $ 390,039 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (114,887 ) (80,480 ) — (195,367 ) Cash distributions received from equity investees - return of investment — — 28,979 — — 28,979 Investments in equity investees — — (3,018 ) — — (3,018 ) Intercompany transfers 503,144 — — — (503,144 ) — Repayments on loan to non-guarantor subsidiary — — 7,484 — (7,484 ) — Proceeds from assets sales — — 310,099 — — 310,099 Net cash (used in) provided by investing activities 503,144 — 228,657 (80,480 ) (510,628 ) 140,693 CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 980,700 — — — — 980,700 Repayments on senior secured credit facility (1,109,800 ) — — — — (1,109,800 ) Repayment of senior unsecured notes (145,170 ) — — — — (145,170 ) Debt issuance costs (242 ) — — — — (242 ) Intercompany transfers — — (485,506 ) (17,638 ) 503,144 — Distributions to partners/owners (257,416 ) — (257,416 ) (123,900 ) 381,316 (257,416 ) Contributions from noncontrolling interest — — — 2,592 — 2,592 Other, net — — (137 ) 13,121 (13,121 ) (137 ) Net cash provided by (used in) financing activities (531,928 ) — (743,059 ) (125,825 ) 871,339 (529,473 ) Net increase in cash and cash equivalents — — (306 ) 1,565 — 1,259 Cash and cash equivalents at beginning of period 6 — 5,230 3,805 — 9,041 Cash and cash equivalents at end of period $ 6 $ — $ 4,924 $ 5,370 $ — $ 10,300 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 162,980 $ — $ 448,873 $ 30,467 $ (318,764 ) $ 323,556 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (236,151 ) (14,442 ) — (250,593 ) Cash distributions received from equity investees - return of investment — — 35,582 — — 35,582 Investments in equity investees (140,513 ) — (4,647 ) — 140,513 (4,647 ) Acquisitions — — (759 ) (1,325,000 ) — (1,325,759 ) Intercompany transfers (1,157,781 ) — (1,325,000 ) — 2,482,781 — Repayments on loan to non-guarantor subsidiary — — 6,764 — (6,764 ) — Contributions in aid of construction costs — — 124 — — 124 Proceeds from asset sales — — 85,722 — — 85,722 Net cash (used in) provided by investing activities (1,298,294 ) — (1,438,365 ) (1,339,442 ) 2,616,530 (1,459,571 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,458,700 — — — — 1,458,700 Repayments on senior secured credit facility (1,637,700 ) — — — — (1,637,700 ) Proceeds from issuance of senior unsecured notes 1,000,000 — — — — 1,000,000 Proceeds from issuance of Series A convertible preferred 726,419 — — — — 726,419 Repayment of senior secured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Distribution to partners/owners (321,875 ) — (321,875 ) (17,500 ) 339,375 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Intercompany transfers — — 1,169,781 1,313,000 (2,482,781 ) — Other, net — — (57 ) 13,847 (13,847 ) (57 ) Net cash provided by (used in) financing activities 1,135,314 — 988,362 1,312,117 (2,297,766 ) 1,138,027 Net increase in cash and cash equivalents — — (1,130 ) 3,142 — 2,012 Cash and cash equivalents at beginning of period 6 — 6,360 663 — 7,029 Cash and cash equivalents at end of period $ 6 $ — $ 5,230 $ 3,805 $ — $ 9,041

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2019segment
Other Ownership Interests [Line Items]
Number of divisions that constitute reportable segments	4
Genesis Energy, LLC
Other Ownership Interests [Line Items]
Limited liability company, ownership interest owned	100.00%

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets	$ 0	$ 0	$ 0
Right of use assets, net	177,071,000	0		$ 208,929,000
Operating lease liability	173,316,000			204,364,000
Reclassification from operating cash flows due to adoption of new accounting pronouncement	(382,287,000)	(390,039,000)	(323,556,000)
Reclassification to investing cash flows due to adoption of new accounting pronouncement	(140,811,000)	$ 140,693,000	(1,459,571,000)
Leases (ASC 840)
Summary Of Significant Accounting Policies [Line Items]
Right of use assets, net				209,000,000
Operating lease liability				209,000,000
Statement of Cash Flows (Topic 230)
Summary Of Significant Accounting Policies [Line Items]
Reclassification from operating cash flows due to adoption of new accounting pronouncement			15,300,000
Reclassification to investing cash flows due to adoption of new accounting pronouncement			$ 15,300,000
Transportation equipment
Summary Of Significant Accounting Policies [Line Items]
Right of use assets, net	98,588,000			$ 117,727,000
Operating lease liability	$ 101,909,000
Minimum | Crude oil pipelines and natural gas pipelines and related assets
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	5 years
Minimum | Marine vessels
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	20 years
Minimum | Onshore facilities, machinery, and equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Minimum | Transportation equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Minimum | Building and improvements
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Maximum | Crude oil pipelines and natural gas pipelines and related assets
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	40 years
Maximum | Marine vessels
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Maximum | Onshore facilities, machinery, and equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Maximum | Transportation equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	7 years
Maximum | Building and improvements
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	20 years
Offshore pipeline transportation | Poseidon Oil Pipeline Company
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	64.00%
Offshore pipeline transportation | Neptune Pipeline Company LLC
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	25.70%
Offshore pipeline transportation | Odyssey Pipeline L.L.C.
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	29.00%

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregated Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenues	$ 604,329	$ 621,697	$ 634,785	$ 620,009	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 2,480,820	$ 2,912,770	$ 2,028,377
Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues									714,192	660,747
Product Sales
Disaggregation of Revenue [Line Items]
Total revenues									1,684,308	2,149,223
Refinery Services
Disaggregation of Revenue [Line Items]
Total revenues									82,320	102,800
Onshore facilities and transportation
Disaggregation of Revenue [Line Items]
Total revenues									821,072	1,233,855	1,042,229
Onshore facilities and transportation | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues									160,431	156,266
Onshore facilities and transportation | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues									660,641	1,077,589
Onshore facilities and transportation | Refinery Services
Disaggregation of Revenue [Line Items]
Total revenues									0	0
Sodium minerals and sulfur services
Disaggregation of Revenue [Line Items]
Total revenues									1,105,987	1,174,434	462,622
Sodium minerals and sulfur services | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues									0	0
Sodium minerals and sulfur services | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues									1,023,667	1,071,634
Sodium minerals and sulfur services | Refinery Services
Disaggregation of Revenue [Line Items]
Total revenues									82,320	102,800
Offshore pipeline transportation services
Disaggregation of Revenue [Line Items]
Total revenues									318,116	284,544	318,239
Offshore pipeline transportation services | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues									318,116	284,544
Offshore pipeline transportation services | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues									0	0
Offshore pipeline transportation services | Refinery Services
Disaggregation of Revenue [Line Items]
Total revenues									0	0
Marine transportation
Disaggregation of Revenue [Line Items]
Total revenues									235,645	219,937	$ 205,287
Marine transportation | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues									235,645	219,937
Marine transportation | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues									0	0
Marine transportation | Refinery Services
Disaggregation of Revenue [Line Items]
Total revenues									$ 0	$ 0

Revenue Recognition (Contract A

Revenue Recognition (Contract Assets and Liabilities) (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Revenue Recognition [Abstract]
Contract Assets, Current		$ 21,912	$ 0
Contract Assets, Non-Current	[1]	54,232	72,241
Contract Liabilities, Current		2,896	0
Contract Liabilities, Non-Current		$ 23,170	$ 26,271
[1]	See Revenue Recognition ( Note 3

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Reset tariff period for transportation contracts	1 year
Balances previously classified as contract liabilities in prior periods that were recognized as revenues	$ 2,000,000	$ 0
Revenues recognized related to performance obligations satisfied or partially satisfied in previous periods	$ 0	$ 0

Revenue Recognition (Revenue Ex

Revenue Recognition (Revenue Expected to be Recognized in Future Periods) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 75,021
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 57,615
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 58,623
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 20,269
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 69,134
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 4,283
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 58,540
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 52,812
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 154,899
Revenue expected timing of satisfaction period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 469,029
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 82,167

Lease Accounting (Major Categor

Lease Accounting (Major Categories of Operating Lease Portfolio) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating Leased Assets [Line Items]
Right of use assets, net	$ 177,071	$ 208,929	$ 0
Accrued liabilities, current	28,406	33,016
Other long-term liabilities, non-current	144,910	171,348
Present value of operating lease liabilities	173,316	204,364
Transportation Equipment
Operating Leased Assets [Line Items]
Right of use assets, net	98,588	117,727
Present value of operating lease liabilities	101,909
Office Space & Equipment
Operating Leased Assets [Line Items]
Right of use assets, net	11,085	14,194
Present value of operating lease liabilities	11,206
Facilities and Equipment
Operating Leased Assets [Line Items]
Right of use assets, net	67,398	$ 77,008
Present value of operating lease liabilities	$ 60,201

Lease Accounting (Narrative) (D

Lease Accounting (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)mi	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Lessor, Lease, Description [Line Items]
Operating lease costs	$ 27,200
Operating rent expense		$ 30,800	$ 36,900
Mileage Credits	$ 24,800	26,200	8,400
Number of miles of pipe leased as lessor | mi	86
Fair value of direct finance lease, current	$ 9,300
Fixed lease payments per year	$ 5,200
Fixed lease interest rate per year	10.25%
Current portion of net investments in direct finance leases		8,400
Marine Transportation
Lessor, Lease, Description [Line Items]
Lease revenue	$ 27,000
Operating Leases, Income Statement, Lease Revenue		27,000	25,100
Onshore facilities and transportation
Lessor, Lease, Description [Line Items]
Lease revenue	6,100
Operating Leases, Income Statement, Lease Revenue		$ 6,600	$ 5,200
Fair value of direct finance lease, current	$ 116,996

Lease Accounting (Maturity of L

Lease Accounting (Maturity of Lease Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Operating Leased Assets [Line Items]
2020	$ 39,783
2021	30,141
2022	25,858
2023	23,163
2024	21,845
Thereafter	152,783
Total Lease Payments	293,573
Less: Interest	(120,257)
Present value of operating lease liabilities	173,316	$ 204,364
Transportation Equipment
Operating Leased Assets [Line Items]
2020	26,355
2021	20,282
2022	18,022
2023	17,160
2024	16,355
Thereafter	27,163
Total Lease Payments	125,337
Less: Interest	(23,428)
Present value of operating lease liabilities	101,909
Office Space & Equipment
Operating Leased Assets [Line Items]
2020	4,119
2021	3,163
2022	2,453
2023	678
2024	689
Thereafter	1,723
Total Lease Payments	12,825
Less: Interest	(1,619)
Present value of operating lease liabilities	11,206
Facilities and Equipment
Operating Leased Assets [Line Items]
2020	9,309
2021	6,696
2022	5,383
2023	5,325
2024	4,801
Thereafter	123,897
Total Lease Payments	155,411
Less: Interest	(95,210)
Present value of operating lease liabilities	$ 60,201

Lease Accounting (Lease Term an

Lease Accounting (Lease Term and Discount Rate) (Details)	Dec. 31, 2019
Leases [Abstract]
Weighted-average remaining lease term	12 years 6 months 10 days
Weighted-average discount rate	7.61%

Lease Accounting (Cash Flow Inf

Lease Accounting (Cash Flow Information) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 44,046
Leased assets obtained in exchange for new operating lease liabilities	$ 198,389

Lease Accounting (Maturity of_2

Lease Accounting (Maturity of Lessor Receipts) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Direct Financing Lease
Total Net Lease Receipts	$ 9,300
Marine Transportation
Operating Leases
2020	20,128
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Total Lease Receipts	20,128
Onshore facilities and transportation
Operating Leases
2020	1,200
2021	1,200
2022	1,200
2023	1,200
2024	1,200
Thereafter	4,100
Total Lease Receipts	10,100
Direct Financing Lease
2020	20,668
2021	20,668
2022	20,668
2023	20,668
2024	20,668
Thereafter	72,336
Total Lease Receipts	175,676
Less: Interest	(58,680)
Total Net Lease Receipts	$ 116,996

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details) - USD ($)	Sep. 01, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 14, 2017
Business Acquisition [Line Items]
Payments to acquire business		$ 0	$ 0	$ 1,325,759,000
Class A Convertible Preferred Units
Business Acquisition [Line Items]
Private placement of convertible preferred units	$ 750,000,000
Class A Convertible Preferred Units | Private Placement
Business Acquisition [Line Items]
Private placement of convertible preferred units	750,000,000
6.500% senior unsecured notes
Business Acquisition [Line Items]
Debt issued, aggregate principal amount		$ 550,000,000	550,000,000
Alkali Business
Business Acquisition [Line Items]
Payments to acquire business	1,325,000,000
Payment to acquire business, working capital	$ 105,000,000
Acquisition related costs			$ 2,000,000	$ 12,000,000
Alkali Business | Minimum
Business Acquisition [Line Items]
Estimated useful lives of property and equipment acquired	2 years
Alkali Business | Maximum
Business Acquisition [Line Items]
Estimated useful lives of property and equipment acquired	30 years
Alkali Business | Class A Convertible Preferred Units | Private Placement
Business Acquisition [Line Items]
Private placement of convertible preferred units	$ 750,000,000
Net proceeds from issuance of preferred units (Note 12)	726,400,000
Alkali Business | 6.500% senior unsecured notes
Business Acquisition [Line Items]
Debt issued, aggregate principal amount	$ 550,000,000				$ 550,000,000
Debt instrument, stated rate	6.50%				6.50%
Proceeds from issuance of debt, net of discount	$ 540,100,000

Acquisitions (Schedule of Purch

Acquisitions (Schedule of Purchase Price Allocation) (Details) - Alkali Business $ in Thousands	Sep. 01, 2017USD ($)
Business Acquisition [Line Items]
Accounts receivable	$ 138,258
Inventories	34,929
Other current assets	13,254
Fixed assets	663,217
Mineral leaseholds	566,019
Intangible assets	800
Other assets	3,612
Accounts payable	(44,547)
Accrued liabilities	(36,884)
Other long-term liabilities	(13,658)
Total purchase price	$ 1,325,000

Acquisitions (Schedule of Selec

Acquisitions (Schedule of Selected Financial Information) (Details) - Alkali Business $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Revenues	$ 277,011
Net income	$ 42,014

Acquisitions (Schedule of Pro F

Acquisitions (Schedule of Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per unit)	$ 0.18	$ (0.62)	$ 0.50
Alkali Business
Pro forma consolidated financial operating results:
Revenues			$ 2,549,438
Net Income Attributable to Genesis Energy, L.P.			108,392
Net Income Available to Common Unitholders			$ 42,768
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per unit)			$ 0.50
Pro forma net income per common unit, basic and diluted (in dollars per unit)			$ 0.35

Receivables (Schedule of Trade

Receivables (Schedule of Trade Accounts Receivables Net) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Accounts receivable - trade	$ 418,064	$ 330,855
Allowance for doubtful accounts	(1,062)	(7,393)	$ (8,468)	$ (6,505)
Accounts receivable - trade, net	$ 417,002	$ 323,462

Receivables (Schedule of Allowa

Receivables (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	$ 7,393	$ 8,468	$ 6,505
Charged to costs and expenses, net of recoveries	(5,572)	31	2,001
Amounts written off	(759)	(1,106)	(38)
Balance at end of period	$ 1,062	$ 7,393	$ 8,468

Inventories (Details)

Inventories (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Inventory Disclosure [Abstract]
Petroleum products	$ 2,721,000	$ 12,203,000
Crude oil	5,271,000	8,379,000
Caustic soda	5,965,000	10,372,000
NaHS	10,845,000	12,400,000
Raw materials - Alkali Operations	6,238,000	5,952,000
Work-in-process - Alkali Operations	8,579,000	2,322,000
Finished goods, net - Alkali Operations	14,168,000	11,402,000
Materials and supplies, net - Alkali Operations	11,350,000	10,490,000
Other	0	11,000
Total	65,137,000	73,531,000
Inventory Write-down	$ 0	$ 1,000,000

Inventories Inventories (Narrat

Inventories Inventories (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Inventory (Narrative) (Details) [Abstract]
Inventory Write-down	$ 0	$ 1,000,000

Fixed Assets and Asset Retire_3

Fixed Assets and Asset Retirement Obligations (Schedule of Fixed Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 5,540,596	$ 5,440,858
Less: Accumulated depreciation	(1,246,121)	(1,023,825)
Net fixed assets	4,294,475	4,417,033
Crude oil pipelines and natural gas pipelines and related assets
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	2,891,489	2,918,285
Onshore facilities, machinery, and equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	640,376	639,023
Onshore facilities, machinery, and equipment | Alkali Business
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	591,547	533,924
Transportation equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	19,864	20,102
Marine vessels
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	979,171	951,597
Land, buildings and improvements
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	238,451	222,242
Office equipment, furniture and fixtures
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	22,645	20,505
Construction in progress
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	115,162	94,025
Other
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 41,891	$ 41,155

Fixed Assets and Asset Retire_4

Fixed Assets and Asset Retirement Obligations (Schedule of Mineral Leaseholds) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Mineral leaseholds	$ 566,019	$ 566,019
Less: Accumulated depletion	(10,194)	(5,538)
Mineral leaseholds, net	$ 555,825	$ 560,481

Fixed Assets and Asset Retire_5

Fixed Assets and Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands	Oct. 11, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations Details [Line Items]
Depreciation expense		$ 295,600	$ 286,000	$ 226,000
Depletion expense		4,700	4,000	1,500
Impairment expense		0	126,282	0
Asset retirement obligation		175,081	239,865	$ 198,187
Current Liabilities - Accrued Liabilities
Asset Retirement Obligations Details [Line Items]
Asset retirement obligation		$ 26,600	67,500
Non-Core Offshore Gas Assets | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Abandonment [Member] | MEXICO
Asset Retirement Obligations Details [Line Items]
Impairment expense			$ 82,000
Onshore facilities and transportation | PRB | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Asset Retirement Obligations Details [Line Items]
Net proceeds received on divestiture of assets	$ 300,000
Gain on sale of assets	38,900
Impairment expense	$ 21,200

Fixed Assets and Asset Retire_6

Fixed Assets and Asset Retirement Obligations (Schedule of Reconciliation of Liability for Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 239,865	$ 198,187
Accretion expense	9,402	10,509
Revisions in timing and estimated costs of AROs	(20,529)	44,319
Settlements	(53,657)	(13,150)
Asset retirement obligations, ending balance	$ 175,081	$ 239,865

Fixed Assets and Asset Retire_7

Fixed Assets and Asset Retirement Obligations (Forecast of Accretion Expense to Asset Retirement Obligations) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Forecast of Future Accretion Expense [Abstract]
2020	$ 8,860
2021	8,939
2022	9,417
2023	10,081
2024	$ 10,792

Equity Investees (Narrative) (D

Equity Investees (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Unamortized excess cost amount	$ 350.9	$ 366.4

Equity Investees (Consolidated

Equity Investees (Consolidated Financial Statements Related to Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Genesis’ share of operating earnings	$ 71,975	$ 59,255	$ 66,814
Amortization of differences attributable to Genesis' carrying value of equity investments	(15,491)	(15,629)	(15,768)
Net equity in earnings	56,484	43,626	51,046
Distributions received	$ 77,331	$ 71,714	$ 82,898

Equity Investees (Schedule of B

Equity Investees (Schedule of Balance Sheet Information for Equity Investees) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets
Current assets	$ 44,129	$ 34,005
Fixed assets, net	321,752	346,864
Other assets	16,739	15,469
Total assets	382,620	396,338
Liabilities and equity
Current liabilities	20,081	18,897
Other liabilities	252,331	250,742
Equity	110,208	126,699
Total liabilities and equity	$ 382,620	$ 396,338

Equity Investees (Schedule of O

Equity Investees (Schedule of Operations for Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
INCOME STATEMENT DATA:
Revenues	$ 209,674	$ 180,056	$ 191,078
Operating Income	155,920	129,160	139,604
Net Income	$ 139,436	$ 115,669	$ 134,479

Intangible Assets, Goodwill a_3

Intangible Assets, Goodwill and Other Assets (Schedule of Intangible Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 220,192	$ 230,908
Accumulated Amortization	81,265	68,306
Carrying Value	$ 138,927	162,602
Other
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	9 years
Gross Carrying Amount	$ 34,291	31,747
Accumulated Amortization	21,480	16,875
Carrying Value	$ 12,811	14,872
Onshore facilities and transportation | Intangible associated with lease (1)
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	15 years
Gross Carrying Amount	$ 0	13,260
Accumulated Amortization	0	5,407
Carrying Value	$ 0	7,853
Marine transportation
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Marine transportation | Contract intangible
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 27,800	27,800
Accumulated Amortization	23,033	17,593
Carrying Value	$ 4,767	10,207
Offshore pipeline transportation
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	19 years
Offshore pipeline transportation | Contract intangible
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 158,101	158,101
Accumulated Amortization	36,752	28,431
Carrying Value	$ 121,349	$ 129,670

Intangible Assets, Goodwill a_4

Intangible Assets, Goodwill and Other Assets (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Intangible Assets, Goodwill And Other Assets [Line Items]
Amortization of expense of intangible assets	$ 18,700	$ 21,800	$ 23,600
Goodwill	301,959	301,959
Sodium minerals and sulfur services
Intangible Assets, Goodwill And Other Assets [Line Items]
Goodwill	$ 301,900	301,900
Onshore facilities and transportation | Supply And Logistics Products And Services [Member]
Intangible Assets, Goodwill And Other Assets [Line Items]
Impairment of goodwill		$ 23,100

Intangible Assets, Goodwill a_5

Intangible Assets, Goodwill and Other Assets (Schedule of Estimated Amortization Expense) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Finite-Lived Intangible Assets [Line Items]
2020	$ 15,312
2021	10,526
2022	10,366
2023	9,976
2024	9,775
Other
Finite-Lived Intangible Assets [Line Items]
2020	2,453
2021	2,168
2022	2,010
2023	1,621
2024	1,421
Marine transportation | Contract intangible
Finite-Lived Intangible Assets [Line Items]
2020	4,538
2021	37
2022	35
2023	34
2024	33
Offshore pipeline transportation | Contract intangible
Finite-Lived Intangible Assets [Line Items]
2020	8,321
2021	8,321
2022	8,321
2023	8,321
2024	$ 8,321

Intangible Assets, Goodwill a_6

Intangible Assets, Goodwill and Other Assets (Schedule of Other Assets) (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
CO2 volumetric production payments, net of amortization		$ 0	$ 890
Deferred marine charges, net	[1]	24,098	28,175
Contract Liabilities	[2]	54,232	72,241
Other deferred costs		15,755	20,401
Other assets, net of amortization		$ 94,085	$ 121,707
[1]	See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 )
[2]	See Revenue Recognition ( Note 3

Debt (Schedule of Obligations U

Debt (Schedule of Obligations Under Debt Arrangements) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 11, 2017	May 21, 2015	May 15, 2014
Debt Instrument [Line Items]
Senior secured credit facility	$ 959,300,000	$ 970,100,000
Unamortized discount an debt issuance costs	30,063,000	37,637,000
Senior unsecured notes, net of debt issuance costs	2,469,937,000	2,462,363,000
Long-term debt, principal	3,459,300,000	3,470,100,000
Total long-term debt, net value	3,429,237,000	3,432,463,000
6.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	750,000,000	750,000,000
Unamortized discount an debt issuance costs	9,349,000	12,763,000
Senior unsecured notes, net of debt issuance costs	740,651,000	737,237,000
6.000% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	400,000,000	400,000,000		$ 400,000,000
Unamortized discount an debt issuance costs	3,557,000	4,624,000
Senior unsecured notes, net of debt issuance costs	396,443,000	395,376,000
5.625% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	350,000,000	350,000,000			$ 350,000,000
Unamortized discount an debt issuance costs	3,923,000	4,820,000
Senior unsecured notes, net of debt issuance costs	346,077,000	345,180,000
6.500% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	550,000,000	550,000,000
Unamortized discount an debt issuance costs	7,020,000	8,241,000
Senior unsecured notes, net of debt issuance costs	542,980,000	541,759,000
6.250% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	450,000,000	450,000,000	$ 450,000,000
Unamortized discount an debt issuance costs	6,214,000	7,189,000
Senior unsecured notes, net of debt issuance costs	443,786,000	442,811,000
Senior secured credit facility
Debt Instrument [Line Items]
Unamortized discount an debt issuance costs	7,600,000	10,800,000
Line of Credit
Debt Instrument [Line Items]
Unamortized discount an debt issuance costs	$ 0	$ 0

Debt (Senior Secured Credit Fac

Debt (Senior Secured Credit Facility) (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
Amended Facility | Accordion
Debt Instrument [Line Items]
Credit facility aggregate maximum borrowing capacity	$ 2,000,000,000
Senior secured credit facility
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Senior secured credit facility, amount outstanding	$ 959,300,000
Total amount available for borrowings, remaining borrowing capacity	739,600,000
Senior secured credit facility | Petroleum Products
Debt Instrument [Line Items]
Senior secured credit facility, amount outstanding	$ 4,300,000
Senior secured credit facility | Maximum
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Debt instrument covenant, requirement leverage ratio	1
Debt instrument covenant, requirement senior secured leverage ratio	1
Debt instrument covenant, requirement interest coverage ratio	1
Senior secured credit facility | Minimum
Debt Instrument [Line Items]
Commitment fee percentage	0.25%
Debt instrument covenant, requirement leverage ratio	5.50
Debt instrument covenant, requirement senior secured leverage ratio	3.75
Debt instrument covenant, requirement interest coverage ratio	3
Senior secured credit facility | Acquisition Period | Maximum
Debt Instrument [Line Items]
Debt instrument covenant, requirement interest coverage ratio	1
Senior secured credit facility | Acquisition Period | Minimum
Debt Instrument [Line Items]
Debt instrument covenant, requirement interest coverage ratio	2.75
Senior secured credit facility | Letter of Credit
Debt Instrument [Line Items]
Letter of credit, fee percentage	2.50%
Letters of credit, outstanding amount	$ 1,100,000
Senior secured credit facility | Letter of Credit | Maximum
Debt Instrument [Line Items]
Letters of credit, outstanding amount	100,000,000
Senior secured credit facility | Amended Facility
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	1,700,000,000
Senior secured credit facility | Amended Facility | Accordion
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	$ 300,000,000
Federal Funds Effective Rate
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	0.50%
Federal Funds Effective Rate | Maximum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.00%
LIBOR Rate | Maximum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.00%
Eurodollar Rate
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	2.50%
Eurodollar Rate | Maximum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	3.00%
Letter of credit, fee percentage	3.00%
Eurodollar Rate | Minimum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.50%
Letter of credit, fee percentage	1.50%
Alternate Base Rate | Maximum
Debt Instrument [Line Items]
Letter of credit, fee percentage	2.00%
Alternate Base Rate | Minimum
Debt Instrument [Line Items]
Letter of credit, fee percentage	0.50%
Applicable Margin
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.50%

Debt (Senior Unsecured Notes) (

Debt (Senior Unsecured Notes) (Details) - USD ($)	Feb. 15, 2018	Dec. 11, 2017	Sep. 01, 2017	Aug. 14, 2017	Jul. 23, 2015	May 21, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 15, 2014	Feb. 08, 2013
Debt Instrument [Line Items]
Loss on extinguishment of debt	$ 3,300,000						$ 0	$ 3,339,000	$ 6,242,000
Debt percentage of principal amount redeemed	101.438%
Redemption of senior unsecured debt							0	145,170,000	204,830,000
Proceeds from issuance of unsecured debt							0	0	$ 1,000,000,000
2021 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal											$ 350,000,000
Debt instrument, stated rate											5.75%
Proceeds used to repay unsecured debt principal		$ 204,800,000
2026 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal		$ 450,000,000					450,000,000	450,000,000
Debt instrument, stated rate		6.25%
Proceeds from issuance of debt, net of discount		$ 441,800,000
2024 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal							350,000,000	350,000,000		$ 350,000,000
Debt instrument, stated rate										5.625%
2023 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal						$ 400,000,000	400,000,000	400,000,000
Debt instrument, stated rate						6.00%
7.875% senior unsecured notes due 2018
Debt Instrument [Line Items]
Debt instrument, stated rate						7.875%
Redemption of senior unsecured debt						$ 350,000,000
2022 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal							750,000,000	750,000,000
Debt instrument, stated rate					6.75%
2022 Notes | Enterprise Offshore Acquisition
Debt Instrument [Line Items]
Senior unsecured notes, principal					$ 750,000,000
Debt instrument, stated rate					6.75%
Proceeds from issuance of debt, net of discount					$ 728,600,000
2025 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal							$ 550,000,000	$ 550,000,000
2025 Notes | Alkali Business
Debt Instrument [Line Items]
Senior unsecured notes, principal			$ 550,000,000	$ 550,000,000
Debt instrument, stated rate			6.50%	6.50%
Proceeds from issuance of debt, net of discount			$ 540,100,000
Proceeds from issuance of unsecured debt				$ 540,100,000

Debt (Redemption Periods Senior

Debt (Redemption Periods Senior Unsecured Notes) (Details)	12 Months Ended
	Dec. 31, 2019
2021 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2022 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2023 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2024 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2025 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2026 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%

Partners' Capital, Mezzanine _3

Partners' Capital, Mezzanine Equity and Distributions (Additional Information Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 24, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		122,579,218	122,579,218
Cash or stock available for distributions, percent usually distributed		100.00%
Days to distribute		45 days
Common units issued (in units)		122,579,218	122,579,218
Price per share of common units issued (in dollars per unit)	$ 30.65
Net proceeds received from sale of units, net of underwriter discounts	$ 140,513
Accumulated distributions attributable to Class A Preferred Unitholders		$ 74,467	$ 69,801	$ 21,995
Class A
Partners Capital And Distributions [Line Items]
Common units issued (in units)	4,600,000
Price per share of common units issued (in dollars per unit)	$ 30.65
Additional common units to purchase (in units)	600,000
Net proceeds received from sale of units, net of underwriter discounts	$ 140,500
Class A | Partners' Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		122,539,221
Class B | Partners' Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		39,997
Class A Convertible Preferred Units
Partners Capital And Distributions [Line Items]
Convertible preferred units outstanding (in units)		25,336,778	24,438,022	22,411,728	0
Accumulated distributions attributable to Class A Preferred Unitholders		$ 74,500

Partners' Capital, Mezzanine _4

Partners' Capital, Mezzanine Equity and Distributions (Distributions Paid) (Details) - USD ($) $ / shares in Units, $ in Thousands

Feb. 14, 2020

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Feb. 14, 2018

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Feb. 14, 2017

Distribution Made to Limited Partner [Line Items]

Per Unit Amount (in dollars per unit)

[1]

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5400

$ 0.5300

$ 0.5200

Common Unitholders [Member]

Distribution Made to Limited Partner [Line Items]

Date Paid

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Feb. 14, 2018

Per Unit Amount (in dollars per unit)

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5400

$ 0.5300

$ 0.5200

$ 0.5100

Total Amount

$ 67,419

$ 67,419

$ 67,419

$ 67,419

$ 66,193

$ 64,967

$ 63,741

$ 62,515

Common Unitholders [Member] | Scenario, Forecast | Subsequent Event

Distribution Made to Limited Partner [Line Items]

Date Paid

Feb. 14, 2020

Per Unit Amount (in dollars per unit)

$ 0.5500

Total Amount

$ 67,419

[1]

(1) Represents cash distributions declared and paid in the applicable period.

Partners' Capital, Mezzanine _5

Partners' Capital, Mezzanine Equity and Distributions (New Common Units Issued to the Public for Cash) (Details) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 24, 2017USD ($)$ / sharesshares
Equity [Abstract]
Units (in units) | shares	4,600
Gross Unit Price (in dollars per unit) | $ / shares	$ 30.65
Issuance Value	$ 140,990
Costs	(477)
Net Proceeds	$ 140,513

Partners' Capital, Mezzanine _6

Partners' Capital, Mezzanine Equity and Distributions (Class A Convertible Preferred Units Narrative) (Details) - Class A Convertible Preferred Units $ / shares in Units, $ in Thousands	Sep. 01, 2024USD ($)directorshares	Sep. 01, 2022	Mar. 01, 2019quarter	Sep. 01, 2017USD ($)buyer$ / sharesshares	Dec. 31, 2019shares	Sep. 01, 2019USD ($)	Dec. 31, 2018shares
Temporary Equity [Line Items]
Private placement of convertible preferred units | $				$ 750,000
Class A convertible preferred units issued (in units)					25,336,778		24,438,022
Number of shares authorized to be converted (in units)				7,416,498
Consecutive period for shares to be converted				12 months
Minimum number of shares outstanding authorized to be converted (in units)				592,768
Volume weighted average price percentage				95.00%
Consideration payable to holders in cash for change of control percentage				90.00%
Threshold trading days to notify holders				30 days
Consecutive trading days in period ending on fifth trading day				30 days
Change in control multiplier price percentage				101.00%
Basis spread			2
Aggregate amount of conversion required, minimum | $						$ 50,000
Number of quarters in trading period | quarter			2
In Arrears At Annual Rate
Temporary Equity [Line Items]
Dividend rate percentage				8.75%
Dividend amount (in dollars per unit) | $ / shares				$ 2.9496
Quarterly Rate
Temporary Equity [Line Items]
Dividend rate percentage				2.1875%
Dividend amount (in dollars per unit) | $ / shares				$ 0.7374
Scenario, Forecast
Temporary Equity [Line Items]
Threshold trading days to notify holders		30 days
Reset rate		10.75%
Percentage below issue price		110.00%
Percentage of holders required to approve rate reset election		25.00%
Multiplier liquidation value percentage prior to September 1, 2024	110.00%
Multiplier liquidation value percentage thereafter	105.00%
Conversion ratio	1
Aggregate amount of ownership required for initial purchasers to attend board meetings | $	$ 200,000
Percentage required for initial purchasers to purchase securities	50.00%
Aggregate number of ownership units required for initial purchasers to appoint directors (in units)	11,124,747
Number of directors that initial purchasers have right to appoint | director	2
Minimum
Temporary Equity [Line Items]
Redemption premium percentage				115.00%
Maximum
Temporary Equity [Line Items]
Redemption premium percentage				101.00%
LIBOR | Scenario, Forecast
Temporary Equity [Line Items]
Basis spread		7.50
Private Placement
Temporary Equity [Line Items]
Private placement of convertible preferred units | $				$ 750,000
Class A convertible preferred units issued (in units)				22,249,494
Cash purchase price per unit (in dollars per unit) | $ / shares				$ 33.71
Number of initial purchasers | buyer				2

Partners' Capital, Mezzanine _7

Partners' Capital, Mezzanine Equity and Distributions (Paid in Kind Distributions Paid) (Details) - Class A Convertible Preferred Units - USD ($) $ in Thousands	May 15, 2019	Feb. 14, 2019	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Distribution Made to Limited Partner [Line Items]
Date Issued	May 15, 2019	Feb. 14, 2019	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2018
Number of Units (in units)	364,180	534,576	523,132	511,934	500,967	490,252	162,234	898,756	2,026,294	162,234
Total Amount	$ 12,277	$ 18,021	$ 17,635	$ 17,257	$ 16,888	$ 16,526	$ 5,469	$ 30,298	$ 68,306	$ 5,469

Partners' Capital, Mezzanine _8

Partners' Capital, Mezzanine Equity and Distributions (Preferred Cash Distributions Paid) (Details) - USD ($) $ / shares in Units, $ in Thousands

Feb. 14, 2020

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Temporary Equity [Line Items]

Per Unit Amount (in dollars per unit)

[1]

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5400

$ 0.5300

$ 0.5200

Class A Convertible Preferred Units | Preferred Unitholders

Temporary Equity [Line Items]

Date Paid

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Per Unit Amount (in dollars per unit)

$ 0.7374

$ 0.7374

$ 0.2458

Total Amount

$ 18,684

$ 18,684

$ 6,138

Scenario, Forecast | Subsequent Event | Class A Convertible Preferred Units | Preferred Unitholders

Temporary Equity [Line Items]

Date Paid

Feb. 14, 2020

Per Unit Amount (in dollars per unit)

$ 0.7374

Total Amount

$ 18,684

[1]

(1) Represents cash distributions declared and paid in the applicable period.

Partners' Capital, Mezzanine _9

Partners' Capital, Mezzanine Equity and Distributions (Initial Measurement of Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	Sep. 01, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016
Temporary Equity [Line Items]
Transaction price, net			$ 790,115	$ 761,466
Class A Convertible Preferred Units
Temporary Equity [Line Items]
Transaction price, gross	$ 750,000
Transaction cost to other third parties	(23,581)
Transaction price, net	726,419	$ 726,419
Preferred Units, net	691,969
Preferred Distribution Rate Reset Election	34,450
Transaction price, net	$ 726,419	$ 697,151	$ 790,115	$ 761,466	$ 0

Partners' Capital, Mezzanine_10

Partners' Capital, Mezzanine Equity and Distributions (Change in Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	May 15, 2019	Feb. 14, 2019	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Sep. 01, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Amount
Beginning Balance									$ 761,466
Ending Balance									$ 790,115	$ 761,466
Class A Convertible Preferred Units
Units
Beginning Balance (in units)									24,438,022	22,411,728	0
Issuance of Preferred Units, net (in units)											22,249,494
Allocation to Preferred Distribution Rate Reset Election (in units)											0
Distribution paid-in-kind (in units)	364,180	534,576	523,132	511,934	500,967	490,252	162,234		898,756	2,026,294	162,234
Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election (in units)									0	0	0
Ending Balance (in units)									25,336,778	24,438,022	22,411,728
Amount
Beginning Balance									$ 761,466	$ 697,151	$ 0
Issuance of Preferred Units, net								$ 726,419			726,419
Allocation to Preferred Distribution Rate Reset Election											(34,450)
Distributions paid-in-kind	$ 12,277	$ 18,021	$ 17,635	$ 17,257	$ 16,888	$ 16,526	$ 5,469		30,298	68,306	5,469
Allocation of Distribution paid-kind to Preferred Distribution Rate Reset Election									(1,649)	(3,991)	(287)
Ending Balance								$ 726,419	$ 790,115	$ 761,466	$ 697,151

Partners' Capital, Mezzanine_11

Partners' Capital, Mezzanine Equity and Distributions (Redeemable Noncontrolling Interest- Narrative) (Details)	Sep. 23, 2019USD ($)dmanager$ / shares	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Redeemable Noncontrolling Interest [Line Items]
Issuance of Preferred Units	$ 55,000,000
Proceeds From Redeemable Noncontrolling Interest							$ 122,900,000
Net income attributable to redeemable noncontrolling interests		$ (1,961,000)		$ (272,000)	$ 0	$ 0	(2,233,000)	$ 0	$ 0
Redemption accretion			$ 455,000
Genesis Alkali Holdings Company, LLC [Member] | Subsidiaries [Member]
Redeemable Noncontrolling Interest [Line Items]
Issuance of Preferred Units	$ 55,000,000						130,000,000
Redeemable Noncontrolling Interest, Equity, Preferred, Commitment Period	3 years
Facility Expansion Costs, Funding Percentage	100.00%
Redeemable Noncontrolling Interest, Equity, Preferred, Annual Percentage For Quarterly Distributions	10.00%
Redeemable Noncontrolling Interest, Equity, Preferred, Liquidation Preference Per Unit | $ / shares	$ 1,000
Redeemable Noncontrolling Interest, Equity, Preferred, Days In Period After End Of Fiscal Quarter To Pay Cash Distributions | d	45
Redeemable Noncontrolling Interest, Equity, Preferred, Period After Initial Closing Date To Pay Distributions Paid-in-kind	36 months
Redeemable Noncontrolling Interest, Equity, Preferred, Minimum Cash Reserve Balance	$ 5,000,000
Redeemable Noncontrolling Interest, Equity, Preferred, Purchase Price Per Unit | $ / shares	$ 1,000
Redeemable Noncontrolling Interest, Equity, Preferred, Period For Triggering Event To Occur	6 years
Net income attributable to redeemable noncontrolling interests							2,300,000
Redeemable Noncontrolling Interest, Equity, Preferred, Paid in Kind Distribution allocation							1,800,000
Redemption accretion							500,000
Redeemable Noncontrolling Interest, Equity, Preferred, Fair Value		$ 192,500,000	$ 192,500,000				$ 192,500,000
Minimum | Genesis Alkali Holdings Company, LLC [Member] | Subsidiaries [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable Noncontrolling Interest, Equity, Preferred, Amount Authorized	$ 250,000,000
Number Board Of Managers | manager	5
Number Of Board Managers Designated By The Partnership | manager	3
Number Of Board Managers Designated By The Sponsor | manager	1
Number Of Independent Board Managers | manager	1
Maximum | Genesis Alkali Holdings Company, LLC [Member] | Subsidiaries [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable Noncontrolling Interest, Equity, Preferred, Amount Authorized	$ 350,000,000

Partners' Capital, Mezzanine_12

Partners' Capital, Mezzanine Equity and Distributions (Changes in Redeemable Noncontrolling Interests) (Details) - USD ($) $ in Thousands	Sep. 23, 2019	Dec. 31, 2019	Dec. 31, 2019
Redeemable Noncontrolling Interest, Equity [Roll Forward]
Issuance of Preferred Units	$ 55,000
Issuance costs	(5,600)
Balance as of September 23, 2019			$ 0
Issuance of preferred units, net of issuance costs		$ 73,500
Distribution paid-in-kind		1,778
Redemption accretion		455
Balance as of December 31, 2019	$ 49,400	$ 125,133	$ 125,133

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Income per Common Unit [Abstract]
Net Income (Loss) Attributable to Genesis Energy L.P.	$ 22,368	$ 17,557	$ 40,120	$ 15,954	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 95,999	$ (6,075)	$ 82,647
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(74,467)	(69,801)	(21,995)
Net Income (Loss) Available to Common Unitholders									$ 21,532	$ (75,876)	$ 60,652
Weighted Average Outstanding Units (in units)									122,579	122,579	121,546
Basic and Diluted (in dollars per unit)									$ 0.18	$ (0.62)	$ 0.50

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019segment
Segment Reporting [Abstract]
Number of divisions that constitute reportable segments	4

Business Segment Information (S

Business Segment Information (Schedule of Revenues by Segment) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total Segment Margin									$ 713,262	$ 712,758	$ 594,543
Total revenues	$ 604,329	$ 621,697	$ 634,785	$ 620,009	$ 689,296	$ 745,278	$ 752,388	$ 725,808	2,480,820	2,912,770	2,028,377
Offshore pipeline transportation
Segment Reporting Information [Line Items]
Total revenues									318,116	284,544	318,239
Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Total revenues									1,105,987	1,174,434	462,622
Sodium minerals and sulfur services | Alkali Business
Segment Reporting Information [Line Items]
Capital Expenditures											1,300,000
Onshore facilities and transportation
Segment Reporting Information [Line Items]
Total revenues									821,072	1,233,855	1,042,229
Marine transportation
Segment Reporting Information [Line Items]
Total revenues									235,645	219,937	205,287
Operating Segments
Segment Reporting Information [Line Items]
Total Segment Margin									713,262	712,758	594,543
Capital Expenditures									173,042	161,393	1,580,821
Total revenues									2,480,820	2,912,770	2,028,377
Operating Segments | Offshore pipeline transportation
Segment Reporting Information [Line Items]
Total Segment Margin									320,023	285,014	317,540
Capital Expenditures									17,809	4,703	8,815
Total revenues									318,116	284,544	319,455
Operating Segments | Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Total Segment Margin									223,908	260,488	130,333
Capital Expenditures									107,837	74,712	1,354,469
Total revenues									1,113,623	1,181,578	470,789
Operating Segments | Onshore facilities and transportation
Segment Reporting Information [Line Items]
Total Segment Margin									111,412	119,918	96,376
Capital Expenditures									6,576	51,110	149,123
Total revenues									824,148	1,240,382	1,044,083
Operating Segments | Marine transportation
Segment Reporting Information [Line Items]
Total Segment Margin									57,919	47,338	50,294
Capital Expenditures									40,820	30,868	68,414
Total revenues									224,933	206,266	194,050
Intersegment
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Intersegment | Offshore pipeline transportation
Segment Reporting Information [Line Items]
Total revenues									0	0	(1,216)
Intersegment | Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Total revenues									(7,636)	(7,144)	(8,167)
Intersegment | Onshore facilities and transportation
Segment Reporting Information [Line Items]
Total revenues									(3,076)	(6,527)	(1,854)
Intersegment | Marine transportation
Segment Reporting Information [Line Items]
Total revenues									$ 10,712	$ 13,671	$ 11,237

Business Segment Information _2

Business Segment Information (Schedule of Total Assets by Reportable Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 6,597,641	$ 6,479,071	$ 7,137,481
Operating Segments | Offshore pipeline transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	2,306,946	2,359,013	2,486,803
Operating Segments | Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
TOTAL ASSETS	2,019,905	1,844,845	1,848,188
Operating Segments | Onshore facilities and transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,457,190	1,431,910	1,927,976
Operating Segments | Marine transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	772,383	800,243	824,777
Other assets
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 41,217	$ 43,060	$ 49,737

Business Segment Information (R

Business Segment Information (Reconciliation of Segment Margin to Net Income) (Details) - USD ($) $ in Thousands	Feb. 15, 2018	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting [Abstract]
Total Segment Margin										$ 713,262	$ 712,758	$ 594,543
Corporate general and administrative expenses										(52,755)	(64,683)	(60,029)
Depreciation, depletion, amortization and accretion										(308,115)	(317,186)	(262,021)
Interest expense										(219,440)	(229,191)	(176,762)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income										(20,847)	(28,088)	(31,852)	[1]
Non-cash items not included in Segment Margin										(14,642)	9,698	(14,305)
Cash payments from direct financing leases in excess of earnings										(8,421)	(7,633)	(6,921)
Loss on debt extinguishment	$ (3,300)									0	(3,339)	(6,242)
Differences in timing of cash receipts for certain contractual arrangements										8,478	6,629	17,540	[2]
Gain on sales of assets										0	42,264	40,311
Other, net										0	0	(2,985)
Non-cash provision for leased items no longer in use										1,367	476	(12,589)
Income tax benefit (expense)										(655)	(1,498)	3,959
Net income attributable to redeemable noncontrolling interests		$ (1,961)	$ (272)	$ 0	$ 0					(2,233)	0	0
Impairment expense										0	(126,282)	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.		$ 22,368	$ 17,557	$ 40,120	$ 15,954	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 95,999	$ (6,075)	$ 82,647
[1]	Includes distributions attributable to the period and received during or promptly following such period.
[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.

Transactions with Related Par_3

Transactions with Related Parties (Schedule of Transactions With Related Parties) (Details) - Affiliated Entity - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017		Sep. 30, 2018
CEO
Related Party Transaction [Line Items]
Related party transaction, expenses	$ 660	$ 660	$ 660
Sandhill Group Llc
Related Party Transaction [Line Items]
Related party transaction, revenues	0	1,233	2,820	[1]
Equity investment, ownership percentage					50.00%
Poseidon Oil Pipeline Company
Related Party Transaction [Line Items]
Related party transaction, revenues	12,669	12,557	12,357	[2]
Related party transaction, expenses	$ 975	994	986	[2]
Equity investment, ownership percentage	64.00%
ANSAC
Related Party Transaction [Line Items]
Related party transaction, revenues	$ 367,133	373,606	124,536
Related party transaction, expenses	$ 4,446	$ 5,284	$ 2,242
[1]	We owned a 50% interest in Sandhill Group, LLC which was sold in the third quarter of 2018.
[2]	We own a 64% interest in Poseidon Oil Pipeline Company, LLC.

Transactions with Related Par_4

Transactions with Related Parties (Narrative) (Details) - Affiliated Entity - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Poseidon Oil Pipeline Company
Related Party Transaction [Line Items]
Net sales from related party	$ 12,669	$ 12,557	$ 12,357	[1]
Due from related parties	2,400	2,400
Costs charged by related party, included in operating costs	975	994	986	[1]
Poseidon Oil Pipeline Company | Asset Management Arrangement
Related Party Transaction [Line Items]
Net sales from related party	8,900	8,600	8,400
ANSAC
Related Party Transaction [Line Items]
Net sales from related party	367,133	373,606	124,536
Due from related parties	68,075	60,594
Costs charged by related party, included in operating costs	$ 4,446	$ 5,284	$ 2,242
[1]	We own a 64% interest in Poseidon Oil Pipeline Company, LLC.

Transactions with Related Par_5

Transactions with Related Parties (Schedule of Receivables From and Payables To Related Parties) (Details) - Affiliated Entity - ANSAC - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Receivables	$ 68,075	$ 60,594
Payables	$ 2,103	$ 815

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Net Changes in Components of Operating Assets and Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
(Increase) decrease in:
Accounts receivable	$ (80,126)	$ 130,573	$ (140,948)
Inventories	7,659	20,963	49,055
Deferred charges	4,093	(5,826)	(3,622)
Other current assets	(4,874)	9,337	(410)
Increase (decrease) in:
Accounts payable	81,915	(130,991)	97,569
Accrued liabilities	(79,765)	(26,208)	8,512
Net changes in components of operating assets and liabilities	$ (71,098)	$ (2,152)	$ 10,156

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Payments of interest and commitment fees	$ 212.4	$ 228.3	$ 168.3
Capitalized interest	3.7	3.4	15
Cash paid for income taxes	0.8	0.2	1
Incurred liabilities for fixed and intangible asset additions	$ 22.6	$ 9.4	$ 39.7

Equity-Based Compensation Pla_3

Equity-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 1,919	$ 1,971	$ (4,577)
Service-Based Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in units)	29,606
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 21.28
Performance-Based Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in units)	0
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 0
2010 Plan | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in units)	29,606	28,484	297,214
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 21.28	$ 22.12	$ 32.37
Unrecognized compensation cost	$ 200
Weighted average period of recognition, years	3 months 18 days
Compensation expense	$ 1,800	$ 2,100
Liability for compensation awards	$ 2,800	$ 3,300
2010 Plan | Service-Based Phantom Units | Anniversary Year 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%
2010 Plan | Service-Based Phantom Units | Anniversary Year 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%
2010 Plan | Service-Based Phantom Units | Anniversary Year 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%
2010 Plan | Performance-Based Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			0.00%
2010 Plan | Performance-Based Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			150.00%
2010 Plan | Performance-Based Phantom Units | Anniversary Year 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%
2010 Plan | Performance-Based Phantom Units | Anniversary Year 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%
2010 Plan | Performance-Based Phantom Units | Anniversary Year 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage			33.33%

Equity-Based Compensation Pla_4

Equity-Based Compensation Plans (Summary of Service-Based and Performance-Based Awards) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / sharesshares
Service-Based Awards
Number of Phantom Units
Unvested at December 31, 2018 (in units) | shares	195,939
Granted (in units) | shares	29,606
Forfeited (in units) | shares	(1,098)
Settled (in units) | shares	(76,370)
Unvested at December 31, 2019 (in units) | shares	148,077
Average Grant Date Fair Value
Unvested at December 31, 2018 (in dollars unit) | $ / shares	$ 30.40
Granted (in dollars per unit) | $ / shares	21.28
Forfeited (in dollars per unit) | $ / shares	32.43
Settled (in dollars per unit) | $ / shares	31.79
Unvested at December 31, 2019 (in dollars per unit) | $ / shares	$ 27.85
Total Value (in thousands)
Unvested at December 31, 2018 | $	$ 5,958
Granted | $	630
Forfeited | $	(36)
Settled | $	(2,428)
Unvested at December 31, 2019 | $	$ 4,124
Performance-Based Awards
Number of Phantom Units
Unvested at December 31, 2018 (in units) | shares	378,006
Granted (in units) | shares	0
Forfeited (in units) | shares	(1,653)
Settled (in units) | shares	(213,582)
Unvested at December 31, 2019 (in units) | shares	162,771
Average Grant Date Fair Value
Unvested at December 31, 2018 (in dollars unit) | $ / shares	$ 31.09
Granted (in dollars per unit) | $ / shares	0
Forfeited (in dollars per unit) | $ / shares	32.43
Settled (in dollars per unit) | $ / shares	30.37
Unvested at December 31, 2019 (in dollars per unit) | $ / shares	$ 32.02
Total Value (in thousands)
Unvested at December 31, 2018 | $	$ 11,754
Granted | $	0
Forfeited | $	(54)
Settled | $	(6,486)
Unvested at December 31, 2019 | $	$ 5,214

Equity-Based Compensation Pla_5

Equity-Based Compensation Plans (Expense Related to Equity-Based Compensation Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ 1,919	$ 1,971	$ (4,577)
Cost of goods and services sold | Onshore facilities and transportation
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	250	140	(1,137)
Cost of goods and services sold | Marine transportation
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	173	183	(483)
Cost of goods and services sold | Sodium minerals and sulfur services
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	140	112	(533)
Cost of goods and services sold | Offshore pipeline transportation
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	269	297	(152)
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ 1,087	$ 1,239	$ (2,272)

Major Customers and Credit Ri_2

Major Customers and Credit Risk (Details) - Customer Concentration Risk - Supply And Logistics Revenues	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
ANSAC
Concentration Risk [Line Items]
Concentration risk, percentage	15.00%	13.00%
Shell Oil Company
Concentration Risk [Line Items]
Concentration risk, percentage	8.00%	11.00%	13.00%

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivatives Entered Into to Hedge Inventory or Fixed Price Purchase Commitments) (Details) bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2019MMBTU$ / bbl$ / MMBTU$ / unitsbbl
Sell (Short) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	19
Weighted average contract price per bbl (in dollars per barrel)	58.57
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	79
Weighted average contract price per bbl (in dollars per barrel)	60.25
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Weighted average contract price per bbl (in dollars per barrel) | $ / MMBTU	2.27
Contract volumes (1,000 MMBTU) | MMBTU	92
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Weighted average contract price per bbl (in dollars per barrel)	0.38
Contract volumes (1,000 MMBTU) | MMBTU	503
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Options | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	40
Weighted average premium received (in dollars per barrel)	1.03
Buy (Long) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	0
Weighted average contract price per bbl (in dollars per barrel)	0
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	80
Weighted average contract price per bbl (in dollars per barrel)	60.25
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Weighted average contract price per bbl (in dollars per barrel) | $ / MMBTU	2.60
Contract volumes (1,000 MMBTU) | MMBTU	576
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Weighted average contract price per bbl (in dollars per barrel) | $ / units	0
Contract volumes (1,000 MMBTU) | MMBTU	0
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Options | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	18
Weighted average premium received (in dollars per barrel)	0.66

Derivatives (Fair Value of Deri

Derivatives (Fair Value of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Liability Derivatives:
Preferred Distribution Rate Reset Election	$ (51,500)
Embedded Derivative Financial Instruments | Other Long-Term Liabilities
Liability Derivatives:
Preferred Distribution Rate Reset Election	(51,515)	$ (40,840)
Not Designated As Hedging Instrument | Commodity Derivatives | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	207	3,431
Gross amount offset in the Consolidated Balance Sheets	(207)	(1,361)
Net amount of assets presented in the Consolidated Balance Sheets	0	2,070
Liability Derivatives:
Gross amount of recognized liabilities	(2,079)	(1,361)
Gross amount offset in the Consolidated Balance Sheets	1,064	1,361
Net amount of liabilities presented in the Consolidated Balance Sheets	(1,015)	0
Not Designated As Hedging Instrument | Swap | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	1,382	1,274
Not Designated As Hedging Instrument | Swap | Current Liabilities - Accrued Liabilities
Liability Derivatives:
Gross amount of recognized liabilities	0	(125)
Designated as Hedging Instrument | Commodity Derivatives | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	4	469
Gross amount offset in the Consolidated Balance Sheets	(4)	(44)
Net amount of assets presented in the Consolidated Balance Sheets	0	425
Liability Derivatives:
Gross amount of recognized liabilities	(50)	(44)
Gross amount offset in the Consolidated Balance Sheets	50	44
Net amount of liabilities presented in the Consolidated Balance Sheets	$ 0	$ 0

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 01, 2022	Mar. 01, 2019
Derivatives, Fair Value [Line Items]
Net broker receivables	$ 0.9	$ 2.2
Margin deposit assets	0.8	3.1
Increase (decrease) in variation margin deposits outstanding	0.1	$ (0.9)
Fair value of embedded derivative liability	$ 51.5
Class A Convertible Preferred Units
Derivatives, Fair Value [Line Items]
Basis spread				2
Class A Convertible Preferred Units | Scenario, Forecast
Derivatives, Fair Value [Line Items]
Reset rate			10.75%
Percentage below issue price			110.00%
Class A Convertible Preferred Units | LIBOR | Scenario, Forecast
Derivatives, Fair Value [Line Items]
Basis spread			7.50

Derivatives (Effects on Consoli

Derivatives (Effects on Consolidated Statements of Operations and Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Embedded Derivative Financial Instruments | Other Income (Expense)
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	$ (9,026)	$ 8,360	$ (10,472)
Designated as Hedging Instrument | Commodity Derivatives | Cost of goods and services sold | Onshore facilities and transportation product costs
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	(786)	(544)	5,116
Not Designated As Hedging Instrument | Commodity Derivatives | Cost of goods and services sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	(8,576)	3,370	3,802
Not Designated As Hedging Instrument | Commodity Derivatives | Cost of goods and services sold | Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	(7,790)	3,914	(1,314)
Not Designated As Hedging Instrument | Swap | Cost of goods and services sold | Sodium minerals and sulfur services operating costs
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	$ 1,941	$ 1,906	$ 0

Fair-Value Measurements (Fair V

Fair-Value Measurements (Fair Value of Financial Assets Liabilities Measured on Recurring Basis) (Details) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Level 1 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 211	$ 3,900
Liabilities	(2,129)	(1,405)
Level 1 | Embedded Derivative Financial Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Level 2 | Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	1,382	1,274
Liabilities	0	(125)
Level 2 | Embedded Derivative Financial Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	0	0
Level 3 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Liabilities	0	0
Level 3 | Embedded Derivative Financial Instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities	$ (51,515)	$ (40,840)

Fair-Value Measurements (Reconc

Fair-Value Measurements (Reconciliation of Changes in Derivatives Classified as Level 3) (Details) - Level 3 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	$ (40,840)	$ (45,209)
Net gain for the period including earnings	(9,026)	8,360
Allocation of Distribution Paid-in-kind	(1,649)	(3,991)
Ending Balance	$ (51,515)	$ (40,840)

Fair-Value Measurements (Narrat

Fair-Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Senior unsecured notes, net of debt issuance costs	$ 2,469,937		$ 2,462,363
Fair value of debt		$ 2,500,000	$ 2,300,000

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019
Alkali Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Period of credited service required by benefit plan	1 year

Employee Benefit Plans (Change

Employee Benefit Plans (Change on Benefit Obligations and Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in benefit obligation:
Benefit Obligation, beginning of year	$ 24,511	$ 22,530
Service Cost	4,351	5,153	$ 1,749
Interest Cost	1,340	862	267
Plan Amendment	6,569	0
Actuarial (Gain) Loss	5,981	(3,816)
Benefits Paid	(461)	(218)
Benefit Obligation, end of year	42,291	24,511	22,530
Change in plan assets:
Fair Value of Plan Assets, beginning of year	15,716	13,306
Actual Return (loss) on Plan Assets	4,025	(1,300)
Employer Contributions	4,771	3,928
Benefits Paid	(461)	(218)
Fair Value of Plan assets, end of year	24,051	15,716	$ 13,306
Funded Status at end of period	(18,240)	(8,795)
Amounts recognized in the Consolidated Balance Sheet:
Non-current assets	0	0
Current liabilities	0	0
Non-current Liabilities	(18,240)	(8,795)
Net Liability at end of year	(18,240)	(8,795)
Amounts recognized in accumulated other comprehensive income (loss):
Prior Service Cost	6,163	0
Net actuarial (gain) loss	2,268	(939)
Amounts recognized in accumulated other comprehensive income ( loss:)	$ 8,431	$ (939)

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Contributions and Future Benefit Payments) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Employer Contributions
Expected 2020 Contributions by Employer	$ 5,850
Future Expected Benefit Payments
2020	824
2021	1,112
2022	1,343
2023	1,537
2024	1,714
2025-2029	$ 11,250

Employee Benefit Plans (Compone

Employee Benefit Plans (Components of Net Periodic Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Retirement Benefits [Abstract]
Service Cost	$ 4,351	$ 5,153	$ 1,749
Interest Cost	1,340	862	267
Expected Return on Assets	(1,252)	(973)	(259)
Amortization of Prior Service Cost	406	0	0
Total Net Periodic Benefit Costs	$ 4,845	$ 5,042	$ 1,757

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value Assumptions) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Weighted average assumptions used to determine benefit obligation:
Discount Rate	3.56%	4.62%
Expected Long-term Rate of Return	6.06%	6.41%

Employee Benefit Plans (Asset T

Employee Benefit Plans (Asset Target Allocation) (Details)	Dec. 31, 2019
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Actual %	55.00%
Equity securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target %	41.00%
Equity securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target %	60.00%
Fixed income securities and other
Defined Benefit Plan Disclosure [Line Items]
Actual %	45.00%
Fixed income securities and other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target %	40.00%
Fixed income securities and other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target %	60.00%

Employee Benefit Plans (Fair _2

Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 24,051	$ 15,716	$ 13,306
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	1,311	506
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	13,192	8,038
Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	9,548	7,172
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	24,051	15,716
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	1,311	506
Level 1 | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	13,192	8,038
Level 1 | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	9,548	7,172
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 2 | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 2 | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 3 | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0	0
Level 3 | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 0	$ 0

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Benefit relating to the U.S. federal corporate tax rate change	$ 0	$ 0	$ 5,270

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal	$ 0	$ 0	$ 0
State	591	810	100
Total current income tax expense	591	810	100
Deferred:
Federal	930	114	(5,530)
State	(866)	574	1,471
Total deferred income tax expense (benefit)	64	688	(4,059)
Income tax expense (benefit)	$ 655	$ 1,498	$ (3,959)

Income Taxes (Deferred Tax Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss carryforwards	$ 12,557	$ 11,057
Other	927	434
Total long-term deferred tax asset	13,484	11,491
Valuation allowances	(2,172)	(1,758)
Total deferred tax assets	11,312	9,733
Deferred tax liabilities:
Fixed assets	(1,958)	(2,893)
Intangible assets	(20,730)	(18,209)
Other	(1,264)	(1,207)
Total long-term liability	(23,952)	(22,309)
Total deferred tax liabilities	(23,952)	(22,309)
Total net deferred tax liability	$ (12,640)	$ (12,576)

Income Taxes (Federal Statutory

Income Taxes (Federal Statutory Income Tax Rate to Income Before Income Taxes) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income (loss) from operations before income taxes	$ 100,721,000	$ (10,294,000)	$ 78,120,000
Partnership income not subject to federal income tax	(99,832,000)	10,824,000	(77,704,000)
Income subject to federal income taxes	889,000	530,000	416,000
Tax expense at federal statutory rate	187,000	111,000	146,000
State income taxes, net of federal tax	729,000	1,285,000	1,396,000
Return to provision, federal and state	(219,000)	(128,000)	(163,000)
Other	(42,000)	230,000	(68,000)
Re-measurement of deferred taxes due to enacted tax rate change	0	0	(5,270,000)
Income tax expense (benefit)	$ 655,000	$ 1,498,000	$ (3,959,000)
Effective tax rate on income from operations before income taxes	1.00%	(15.00%)	(5.00%)
Liability for uncertain tax positions	$ 0	$ 0	$ 0

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Revenues from continuing operations		$ 604,329	$ 621,697	$ 634,785	$ 620,009	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 2,480,820	$ 2,912,770	$ 2,028,377
Operating income		70,939	52,787	86,948	62,029	4,119	46,148	60,900	59,081	272,703	170,248	220,551
Net income (loss)		24,660	17,807	41,652	15,947	(28,927)	(1,634)	10,871	7,898	100,066	(11,792)	82,079
Net loss (income) attributable to noncontrolling interests		(331)	22	(1,532)	7	4,144	1,311	126	136	(1,834)	5,717	568
Net income attributable to redeemable noncontrolling interests		(1,961)	(272)	0	0					(2,233)	0	0
Net income attributable to Genesis Energy, L.P.		$ 22,368	$ 17,557	$ 40,120	$ 15,954	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 95,999	$ (6,075)	$ 82,647
Basic and diluted net income (loss) per common unit:
Net income per common unit (in dollars per unit)		$ 0.03	$ (0.01)	$ 0.17	$ (0.02)	$ (0.35)	$ (0.15)	$ (0.05)	$ (0.07)
Cash distributions per common unit (in dollars per unit)	[1]	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5500	$ 0.5500
[1]	(1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information (Narrative) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2019USD ($)
Condensed Financial Statements, Captions [Line Items]
Guaranty obligation	$ 2.5
Genesis NEJD Pipeline, LLC
Condensed Financial Statements, Captions [Line Items]
Percentage of equity interest	100.00%

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Sep. 23, 2019	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
ASSETS
Cash and cash equivalents		$ 29,128			$ 10,300
Restricted cash		27,277			0
Other current assets		536,669			432,979
Total current assets		593,074			443,279
Fixed assets, at cost		5,540,596			5,440,858
Less: Accumulated depreciation		(1,246,121)			(1,023,825)
Net fixed assets		4,294,475			4,417,033
Mineral Leaseholds, net of accumulated depletion		555,825			560,481
Goodwill		301,959			301,959
Other assets, net of amortization		340,714			401,234
Advances to affiliates		0			0
Equity investees		334,523			355,085
Investments in subsidiaries		0			0
Right of use assets, net		177,071		$ 208,929	0
TOTAL ASSETS		6,597,641			6,479,071	$ 7,137,481
LIABILITIES AND CAPITAL
Current liabilities		415,495			332,834
Senior secured credit facility		959,300			970,100
Senior unsecured notes, net of debt issuance costs		2,469,937			2,462,363
Deferred tax liabilities		12,640			12,576
Advances from affiliates		0			0
Other liabilities		393,850			259,198
Total liabilities		4,251,222			4,037,071
Mezzanine Capital:
Class A Convertible Preferred Units		790,115			761,466
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		125,133	$ 49,400		0
Partners’ capital, common units		1,443,320			1,690,799
Accumulated other comprehensive income (loss)	[1]	(8,431)			939
Noncontrolling interests		(3,718)			(11,204)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		6,597,641			6,479,071
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
ASSETS
Cash and cash equivalents		6			6
Restricted cash		0
Other current assets		50			50
Total current assets		56			56
Fixed assets, at cost		0			0
Less: Accumulated depreciation		0			0
Net fixed assets		0			0
Mineral Leaseholds, net of accumulated depletion		0			0
Goodwill		0			0
Other assets, net of amortization		7,583			10,776
Advances to affiliates		3,039,468			3,305,568
Equity investees		0			0
Investments in subsidiaries		2,706,095			2,648,510
Right of use assets, net		0
TOTAL ASSETS		5,753,202			5,964,910
LIABILITIES AND CAPITAL
Current liabilities		39,015			39,342
Senior secured credit facility		959,300			970,100
Senior unsecured notes, net of debt issuance costs		2,469,937			2,462,363
Deferred tax liabilities		0			0
Advances from affiliates		0			0
Other liabilities		51,515			40,840
Total liabilities		3,519,767			3,512,645
Mezzanine Capital:
Class A Convertible Preferred Units		790,115			761,466
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		0
Partners’ capital, common units		1,443,320			1,690,799
Accumulated other comprehensive income (loss)	[1]	0			0
Noncontrolling interests		0			0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		5,753,202			5,964,910
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
ASSETS
Cash and cash equivalents		0			0
Restricted cash		0
Other current assets		0			0
Total current assets		0			0
Fixed assets, at cost		0			0
Less: Accumulated depreciation		0			0
Net fixed assets		0			0
Mineral Leaseholds, net of accumulated depletion		0			0
Goodwill		0			0
Other assets, net of amortization		0			0
Advances to affiliates		0			0
Equity investees		0			0
Investments in subsidiaries		0			0
Right of use assets, net		0
TOTAL ASSETS		0			0
LIABILITIES AND CAPITAL
Current liabilities		0			0
Senior secured credit facility		0			0
Senior unsecured notes, net of debt issuance costs		0			0
Deferred tax liabilities		0			0
Advances from affiliates		0			0
Other liabilities		0			0
Total liabilities		0			0
Mezzanine Capital:
Class A Convertible Preferred Units		0			0
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		0
Partners’ capital, common units		0			0
Accumulated other comprehensive income (loss)	[1]	0			0
Noncontrolling interests		0			0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		0			0
Reportable Legal Entities | Guarantor Subsidiaries
ASSETS
Cash and cash equivalents		7,269			4,924
Restricted cash		0
Other current assets		316,166			229,411
Total current assets		323,435			234,335
Fixed assets, at cost		4,627,696			4,602,164
Less: Accumulated depreciation		(1,089,246)			(926,830)
Net fixed assets		3,538,450			3,675,334
Mineral Leaseholds, net of accumulated depletion		0			0
Goodwill		301,959			301,959
Other assets, net of amortization		403,277			435,540
Advances to affiliates		0			0
Equity investees		334,523			355,085
Investments in subsidiaries		1,420,664			1,413,334
Right of use assets, net		83,942
TOTAL ASSETS		6,406,250			6,415,587
LIABILITIES AND CAPITAL
Current liabilities		253,926			177,104
Senior secured credit facility		0			0
Senior unsecured notes, net of debt issuance costs		0			0
Deferred tax liabilities		12,640			12,576
Advances from affiliates		3,198,277			3,411,515
Other liabilities		245,424			174,249
Total liabilities		3,710,267			3,775,444
Mezzanine Capital:
Class A Convertible Preferred Units		0			0
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		0
Partners’ capital, common units		2,695,983			2,640,143
Accumulated other comprehensive income (loss)	[1]	0			0
Noncontrolling interests		0			0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		6,406,250			6,415,587
Reportable Legal Entities | Non-Guarantor Subsidiaries
ASSETS
Cash and cash equivalents		21,853			5,370
Restricted cash		27,277
Other current assets		220,526			203,683
Total current assets		269,656			209,053
Fixed assets, at cost		912,900			838,694
Less: Accumulated depreciation		(156,875)			(96,995)
Net fixed assets		756,025			741,699
Mineral Leaseholds, net of accumulated depletion		555,825			560,481
Goodwill		0			0
Other assets, net of amortization		109,862			122,538
Advances to affiliates		158,798			105,917
Equity investees		0			0
Investments in subsidiaries		0			0
Right of use assets, net		93,129
TOTAL ASSETS		1,943,295			1,739,688
LIABILITIES AND CAPITAL
Current liabilities		122,673			116,498
Senior secured credit facility		0			0
Senior unsecured notes, net of debt issuance costs		0			0
Deferred tax liabilities		0			0
Advances from affiliates		0			0
Other liabilities		276,789			211,590
Total liabilities		399,462			328,088
Mezzanine Capital:
Class A Convertible Preferred Units		0			0
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		125,133
Partners’ capital, common units		1,430,849			1,421,865
Accumulated other comprehensive income (loss)	[1]	(8,431)			939
Noncontrolling interests		(3,718)			(11,204)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		1,943,295			1,739,688
Eliminations
ASSETS
Cash and cash equivalents		0			0
Restricted cash		0
Other current assets		(73)			(165)
Total current assets		(73)			(165)
Fixed assets, at cost		0			0
Less: Accumulated depreciation		0			0
Net fixed assets		0			0
Mineral Leaseholds, net of accumulated depletion		0			0
Goodwill		0			0
Other assets, net of amortization		(180,008)			(167,620)
Advances to affiliates		(3,198,266)			(3,411,485)
Equity investees		0			0
Investments in subsidiaries		(4,126,759)			(4,061,844)
Right of use assets, net		0
TOTAL ASSETS		(7,505,106)			(7,641,114)
LIABILITIES AND CAPITAL
Current liabilities		(119)			(110)
Senior secured credit facility		0			0
Senior unsecured notes, net of debt issuance costs		0			0
Deferred tax liabilities		0			0
Advances from affiliates		(3,198,277)			(3,411,515)
Other liabilities		(179,878)			(167,481)
Total liabilities		(3,378,274)			(3,579,106)
Mezzanine Capital:
Class A Convertible Preferred Units		0			0
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at December 31, 2019		0
Partners’ capital, common units		(4,126,832)			(4,062,008)
Accumulated other comprehensive income (loss)	[1]	0			0
Noncontrolling interests		0			0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL		$ (7,505,106)			$ (7,641,114)
[1]	The entire balance and activity within Accumulated Other Comprehensive Income (loss) is related to our pension plan held within our Non-Guarantor Subsidiaries.

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES:
Total revenues	$ 604,329	$ 621,697	$ 634,785	$ 620,009	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 2,480,820	$ 2,912,770	$ 2,028,377
COSTS AND EXPENSES:
General and administrative									52,687	66,898	66,421
Depreciation, depletion and amortization									319,806	313,190	252,480
Gain on sale of assets									0	(42,264)	(40,311)
Impairment expense									0	126,282	0
Total costs and expenses									2,208,117	2,742,522	1,807,826
OPERATING INCOME	70,939	52,787	86,948	62,029	4,119	46,148	60,900	59,081	272,703	170,248	220,551
Equity in earnings of equity investees									56,484	43,626	51,046
Equity in earnings of subsidiaries									0	0	0
Interest expense									(219,440)	(229,191)	(176,762)
Other income (expense)									(9,026)	5,023	(16,715)
Income (loss) from operations before income taxes									100,721	(10,294)	78,120
Income tax benefit (expense)									(655)	(1,498)	3,959
NET INCOME (LOSS)	24,660	17,807	41,652	15,947	(28,927)	(1,634)	10,871	7,898	100,066	(11,792)	82,079
Net loss (income) attributable to noncontrolling interests	(331)	22	(1,532)	7	4,144	1,311	126	136	(1,834)	5,717	568
Net income attributable to redeemable noncontrolling interests	(1,961)	(272)	0	0					(2,233)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$ 22,368	$ 17,557	$ 40,120	$ 15,954	$ (24,783)	$ (323)	$ 10,997	$ 8,034	95,999	(6,075)	82,647
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(74,467)	(69,801)	(21,995)
Net Income (Loss) Available to Common Unitholders									21,532	(75,876)	60,652
Offshore pipeline transportation
REVENUES:
Total revenues									318,116	284,544	318,239
COSTS AND EXPENSES:
Cost of products and services sold									58,996	66,668	72,065
Sodium minerals and sulfur services
REVENUES:
Total revenues									1,105,987	1,174,434	462,622
COSTS AND EXPENSES:
Cost of products and services sold									883,692	912,491	333,918
Marine transportation
REVENUES:
Total revenues									235,645	219,937	205,287
COSTS AND EXPENSES:
Cost of products and services sold									178,032	172,527	154,606
Onshore facilities and transportation
REVENUES:
Total revenues									821,072	1,233,855	1,042,229
COSTS AND EXPENSES:
Cost of products and services sold									714,904	1,126,730	968,647
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets										0	0
Impairment expense										0
Total costs and expenses									0	0	0
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									327,257	219,615	276,341
Interest expense									(222,232)	(230,713)	(176,979)
Other income (expense)									(9,026)	5,023	(16,715)
Income (loss) from operations before income taxes									95,999	(6,075)	82,647
Income tax benefit (expense)									0	0	0
NET INCOME (LOSS)									95,999	(6,075)	82,647
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to redeemable noncontrolling interests									0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									95,999	(6,075)	82,647
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(74,467)	(69,801)	(21,995)
Net Income (Loss) Available to Common Unitholders									21,532	(75,876)	60,652
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer) | Offshore pipeline transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer) | Sodium minerals and sulfur services
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer) | Marine transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer) | Onshore facilities and transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets										0	0
Impairment expense										0
Total costs and expenses									0	0	0
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									0	0	0
Interest expense									0	0	0
Other income (expense)									0	0	0
Income (loss) from operations before income taxes									0	0	0
Income tax benefit (expense)									0	0	0
NET INCOME (LOSS)									0	0	0
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to redeemable noncontrolling interests									0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									0	0	0
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									0	0	0
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer) | Offshore pipeline transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer) | Sodium minerals and sulfur services
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer) | Marine transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer) | Onshore facilities and transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Guarantor Subsidiaries
REVENUES:
Total revenues									1,617,171	2,052,211	1,732,671
COSTS AND EXPENSES:
General and administrative									51,191	65,481	65,862
Depreciation, depletion and amortization									242,227	249,820	232,303
Gain on sale of assets										(42,264)	(40,311)
Impairment expense										100,093
Total costs and expenses									1,454,039	1,995,030	1,566,467
OPERATING INCOME									163,132	57,181	166,204
Equity in earnings of equity investees									56,484	43,626	51,046
Equity in earnings of subsidiaries									96,263	107,684	41,494
Interest expense									12,211	13,027	13,825
Other income (expense)									0	0	0
Income (loss) from operations before income taxes									328,090	221,518	272,569
Income tax benefit (expense)									(649)	(1,727)	3,928
NET INCOME (LOSS)									327,441	219,791	276,497
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to redeemable noncontrolling interests									0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									327,441	219,791	276,497
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									327,441	219,791	276,497
Reportable Legal Entities | Guarantor Subsidiaries | Offshore pipeline transportation
REVENUES:
Total revenues									318,116	284,544	318,239
COSTS AND EXPENSES:
Cost of products and services sold									68,167	64,272	69,225
Reportable Legal Entities | Guarantor Subsidiaries | Sodium minerals and sulfur services
REVENUES:
Total revenues									260,675	333,495	185,852
COSTS AND EXPENSES:
Cost of products and services sold									200,845	259,573	117,224
Reportable Legal Entities | Guarantor Subsidiaries | Marine transportation
REVENUES:
Total revenues									235,645	219,937	205,287
COSTS AND EXPENSES:
Cost of products and services sold									178,032	172,527	154,606
Reportable Legal Entities | Guarantor Subsidiaries | Onshore facilities and transportation
REVENUES:
Total revenues									802,735	1,214,235	1,023,293
COSTS AND EXPENSES:
Cost of products and services sold									713,577	1,125,528	967,558
Reportable Legal Entities | Non-Guarantor Subsidiaries
REVENUES:
Total revenues									871,286	875,841	305,199
COSTS AND EXPENSES:
General and administrative									1,496	1,417	559
Depreciation, depletion and amortization									77,579	63,370	20,177
Gain on sale of assets										0	0
Impairment expense										26,189
Total costs and expenses									761,715	762,774	250,852
OPERATING INCOME									109,571	113,067	54,347
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									0	0	0
Interest expense									(9,419)	(11,505)	(13,608)
Other income (expense)									0	0	0
Income (loss) from operations before income taxes									100,152	101,562	40,739
Income tax benefit (expense)									(6)	229	31
NET INCOME (LOSS)									100,146	101,791	40,770
Net loss (income) attributable to noncontrolling interests									(1,834)	5,717	568
Net income attributable to redeemable noncontrolling interests									(2,233)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									96,079	107,508	41,338
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									96,079	107,508	41,338
Reportable Legal Entities | Non-Guarantor Subsidiaries | Offshore pipeline transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									(9,171)	2,396	2,840
Reportable Legal Entities | Non-Guarantor Subsidiaries | Sodium minerals and sulfur services
REVENUES:
Total revenues									852,949	856,221	286,263
COSTS AND EXPENSES:
Cost of products and services sold									690,484	668,200	226,187
Reportable Legal Entities | Non-Guarantor Subsidiaries | Marine transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Reportable Legal Entities | Non-Guarantor Subsidiaries | Onshore facilities and transportation
REVENUES:
Total revenues									18,337	19,620	18,936
COSTS AND EXPENSES:
Cost of products and services sold									1,327	1,202	1,089
Eliminations
REVENUES:
Total revenues									(7,637)	(15,282)	(9,493)
COSTS AND EXPENSES:
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets										0	0
Impairment expense										0
Total costs and expenses									(7,637)	(15,282)	(9,493)
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									(423,520)	(327,299)	(317,835)
Interest expense									0	0	0
Other income (expense)									0	0	0
Income (loss) from operations before income taxes									(423,520)	(327,299)	(317,835)
Income tax benefit (expense)									0	0	0
NET INCOME (LOSS)									(423,520)	(327,299)	(317,835)
Net loss (income) attributable to noncontrolling interests									0	0	0
Net income attributable to redeemable noncontrolling interests									0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									(423,520)	(327,299)	(317,835)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									(423,520)	(327,299)	(317,835)
Eliminations | Offshore pipeline transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Eliminations | Sodium minerals and sulfur services
REVENUES:
Total revenues									(7,637)	(15,282)	(9,493)
COSTS AND EXPENSES:
Cost of products and services sold									(7,637)	(15,282)	(9,493)
Eliminations | Marine transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									0	0	0
Eliminations | Onshore facilities and transportation
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									$ 0	$ 0	$ 0

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 382,287	$ 390,039	$ 323,556
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(163,248)	(195,367)	(250,593)
Cash distributions received from equity investees—return of investment	21,250	28,979	35,582
Investments in equity investees	0	(3,018)	(4,647)
Acquisitions	0	0	(1,325,759)
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	0	0	124
Proceeds from asset sales	1,187	310,099	85,722
Net cash used in (provided by) investing activities	(140,811)	140,693	(1,459,571)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	815,100	980,700	1,458,700
Repayments on senior secured credit facility	(825,900)	(1,109,800)	(1,637,700)
Proceeds from issuance of senior unsecured notes	0	0	1,000,000
Net proceeds from issuance of preferred units (Note 12)	122,900	0	726,419
Repayment of senior unsecured notes	0	(145,170)	(204,830)
Debt issuance costs	0	(242)	(25,913)
Intercompany transfers	0	0	0
Issuance of common units for cash, net	0	0	140,513
Distributions to partners/owners	(269,674)	(257,416)	(321,875)
Distributions to preferred unitholders	(43,506)	0	0
Contributions from noncontrolling interests	5,652	2,592	2,770
Other, net	57	(137)	(57)
Net cash provided by (used in) financing activities	(195,371)	(529,473)	1,138,027
Net increase in cash and cash equivalents and restricted cash	46,105	1,259	2,012
Cash and cash equivalents and restricted cash at beginning of period	10,300	9,041	7,029
Cash and cash equivalents and restricted cash at end of period	56,405	10,300	9,041
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	101,385	28,784	162,980
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees—return of investment	0	0	0
Investments in equity investees	0	0	(140,513)
Acquisitions			0
Intercompany transfers	222,595	503,144	(1,157,781)
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs			0
Proceeds from asset sales	0	0	0
Net cash used in (provided by) investing activities	222,595	503,144	(1,298,294)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	815,100	980,700	1,458,700
Repayments on senior secured credit facility	(825,900)	(1,109,800)	(1,637,700)
Proceeds from issuance of senior unsecured notes			1,000,000
Net proceeds from issuance of preferred units (Note 12)	0		726,419
Repayment of senior unsecured notes		(145,170)	(204,830)
Debt issuance costs		(242)	(25,913)
Intercompany transfers	0	0	0
Issuance of common units for cash, net			140,513
Distributions to partners/owners	(269,674)	(257,416)	(321,875)
Distributions to preferred unitholders	(43,506)
Contributions from noncontrolling interests	0	0	0
Other, net	0	0	0
Net cash provided by (used in) financing activities	(323,980)	(531,928)	1,135,314
Net increase in cash and cash equivalents and restricted cash	0	0	0
Cash and cash equivalents and restricted cash at beginning of period	6	6	6
Cash and cash equivalents and restricted cash at end of period	6	6	6
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	0	0
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees—return of investment	0	0	0
Investments in equity investees	0	0	0
Acquisitions			0
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs			0
Proceeds from asset sales	0	0	0
Net cash used in (provided by) investing activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes			0
Net proceeds from issuance of preferred units (Note 12)	0		0
Repayment of senior unsecured notes		0	0
Debt issuance costs		0	0
Intercompany transfers	0	0	0
Issuance of common units for cash, net			0
Distributions to partners/owners	0	0	0
Distributions to preferred unitholders	0
Contributions from noncontrolling interests	0	0	0
Other, net	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net increase in cash and cash equivalents and restricted cash	0	0	0
Cash and cash equivalents and restricted cash at beginning of period	0	0	0
Cash and cash equivalents and restricted cash at end of period	0	0	0
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	585,788	514,096	448,873
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(80,141)	(114,887)	(236,151)
Cash distributions received from equity investees—return of investment	21,250	28,979	35,582
Investments in equity investees	0	(3,018)	(4,647)
Acquisitions			(759)
Intercompany transfers	0	0	(1,325,000)
Repayments on loan to non-guarantor subsidiary	8,281	7,484	6,764
Contributions in aid of construction costs			124
Proceeds from asset sales	1,187	310,099	85,722
Net cash used in (provided by) investing activities	(49,423)	228,657	(1,438,365)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes			0
Net proceeds from issuance of preferred units (Note 12)	0		0
Repayment of senior unsecured notes		0	0
Debt issuance costs		0	0
Intercompany transfers	(220,897)	(485,506)	1,169,781
Issuance of common units for cash, net			140,513
Distributions to partners/owners	(269,674)	(257,416)	(321,875)
Distributions to preferred unitholders	(43,506)
Contributions from noncontrolling interests	0	0	0
Other, net	57	(137)	(57)
Net cash provided by (used in) financing activities	(534,020)	(743,059)	988,362
Net increase in cash and cash equivalents and restricted cash	2,345	(306)	(1,130)
Cash and cash equivalents and restricted cash at beginning of period	4,924	5,230	6,360
Cash and cash equivalents and restricted cash at end of period	7,269	4,924	5,230
Reportable Legal Entities | Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	82,070	207,870	30,467
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(83,107)	(80,480)	(14,442)
Cash distributions received from equity investees—return of investment	0	0	0
Investments in equity investees	0	0	0
Acquisitions			(1,325,000)
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs			0
Proceeds from asset sales	0	0	0
Net cash used in (provided by) investing activities	(83,107)	(80,480)	(1,339,442)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes			0
Net proceeds from issuance of preferred units (Note 12)	122,900		0
Repayment of senior unsecured notes		0	0
Debt issuance costs		0	0
Intercompany transfers	(1,697)	(17,638)	1,313,000
Issuance of common units for cash, net			0
Distributions to partners/owners	(94,375)	(123,900)	(17,500)
Distributions to preferred unitholders	0
Contributions from noncontrolling interests	5,652	2,592	2,770
Other, net	12,317	13,121	13,847
Net cash provided by (used in) financing activities	44,797	(125,825)	1,312,117
Net increase in cash and cash equivalents and restricted cash	43,760	1,565	3,142
Cash and cash equivalents and restricted cash at beginning of period	5,370	3,805	663
Cash and cash equivalents and restricted cash at end of period	49,130	5,370	3,805
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(386,956)	(360,711)	(318,764)
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees—return of investment	0	0	0
Investments in equity investees	0	0	140,513
Acquisitions			0
Intercompany transfers	(222,595)	(503,144)	2,482,781
Repayments on loan to non-guarantor subsidiary	(8,281)	(7,484)	(6,764)
Contributions in aid of construction costs			0
Proceeds from asset sales	0	0	0
Net cash used in (provided by) investing activities	(230,876)	(510,628)	2,616,530
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes			0
Net proceeds from issuance of preferred units (Note 12)	0		0
Repayment of senior unsecured notes		0	0
Debt issuance costs		0	0
Intercompany transfers	222,594	503,144	(2,482,781)
Issuance of common units for cash, net			(140,513)
Distributions to partners/owners	364,049	381,316	339,375
Distributions to preferred unitholders	43,506
Contributions from noncontrolling interests	0	0	0
Other, net	(12,317)	(13,121)	(13,847)
Net cash provided by (used in) financing activities	617,832	871,339	(2,297,766)
Net increase in cash and cash equivalents and restricted cash	0	0	0
Cash and cash equivalents and restricted cash at beginning of period	0	0	0
Cash and cash equivalents and restricted cash at end of period	$ 0	$ 0	$ 0

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Jan. 16, 2020	Dec. 31, 2019	Dec. 31, 2018	Jul. 23, 2015
6.750% senior unsecured notes
Subsequent Event [Line Items]
Debt issued, aggregate principal amount		$ 750,000	$ 750,000
Debt instrument, stated rate				6.75%
Subsequent Event | 7.75% senior unsecured notes
Subsequent Event [Line Items]
Debt issued, aggregate principal amount	$ 750,000
Debt instrument, stated rate	7.75%
Proceeds from issuance of debt, net of discount	$ 738,900
Proceeds to repay unsecured debt principal, accrued interest and tender premium	$ 554,800