Genesis Energy (GEL) 8-K 19 Dec 19 Other Events Financial data

Cover page

Cover page	Dec. 19, 2019
Cover page.
Document Type	8-K
Document Period End Date	Dec. 19, 2019
Entity Registrant Name	GENESIS ENERGY LP
Entity Incorporation, State or Country Code	DE
Entity File Number	1-12295
Entity Tax Identification Number	76-0513049
Entity Address, Address Line One	919 Milam
Entity Address, Address Line Two	Suite 2100,
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
Written Communications	false
Soliciting Material	false
Pre-commencement Tender Offer	false
Pre-commencement Issuer Tender Offer	false
Title of 12(b) Security	Common Units
Trading Symbol	GEL
Security Exchange Name	NYSE
Entity Emerging Growth Company	false
Entity Central Index Key	0001022321
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 10,300	$ 9,041
Accounts receivable—trade, net	323,462	495,449
Inventories	73,531	88,653
Other	35,986	42,890
Total current assets	443,279	636,033
FIXED ASSETS, at cost	5,440,858	5,601,015
Less: Accumulated depreciation	(1,023,825)	(734,986)
Net fixed assets	4,417,033	4,866,029
MINERALS LEASEHOLDS, net of accumulated depletion	560,481	564,506
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	116,925	125,283
EQUITY INVESTEES	355,085	381,550
INTANGIBLE ASSETS, net of amortization	162,602	182,406
GOODWILL	301,959	325,046
OTHER ASSETS, net of amortization	121,707	56,628
TOTAL ASSETS	6,479,071	7,137,481
CURRENT LIABILITIES:
Accounts payable—trade	127,327	270,855
Accrued liabilities	205,507	185,409
Total current liabilities	332,834	456,264
SENIOR SECURED CREDIT FACILITY	970,100	1,099,200
SENIOR UNSECURED NOTES, net of debt issuance costs	2,462,363	2,598,918
DEFERRED TAX LIABILITIES	12,576	11,913
OTHER LONG-TERM LIABILITIES	259,198	256,571
Total liabilities	4,037,071	4,422,866
MEZZANINE CAPITAL
Class A Convertible Preferred Units, 24,438,022 and 22,411,728 issued and outstanding at December 31, 2018 and 2017, respectively	761,466	697,151
COMMITMENTS AND CONTINGENCIES (Note 22)
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 122,579,218 units issued and outstanding at December 31, 2018 and 2017, respectively	1,690,799	2,026,147
Accumulated other comprehensive income (loss)	939	(604)
Noncontrolling interests	(11,204)	(8,079)
Total partners' capital	1,680,534	2,017,464
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$ 6,479,071	$ 7,137,481

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Class A convertible preferred units issued (in units)	24,438,022	22,411,728
Class A convertible preferred units outstanding (in units)	24,438,022	22,411,728
Common units issued (in units)	122,579,218	122,579,218
Common units outstanding (in units)	122,579,218	122,579,218

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REVENUES:
Total revenues	$ 2,912,770	$ 2,028,377	$ 1,712,493
COSTS AND EXPENSES:
General and administrative	66,898	66,421	45,625
Depreciation, depletion and amortization	313,190	252,480	222,196
Impairment expense	126,282	0	0
Gain on sale of assets	(42,264)	(40,311)	0
Total costs and expenses	2,742,522	1,807,826	1,506,066
OPERATING INCOME	170,248	220,551	206,427
Equity in earnings of equity investees	43,626	51,046	47,944
Interest expense	(229,191)	(176,762)	(139,947)
Other income (expense)	5,023	(16,715)	0
Income (loss) from operations before income taxes	(10,294)	78,120	114,424
Income tax benefit (expense)	(1,498)	3,959	(3,342)
NET INCOME (LOSS)	(11,792)	82,079	111,082
Net loss attributable to noncontrolling interests	5,717	568	2,167
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	(6,075)	82,647	113,249
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(69,801)	(21,995)	0
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS	$ (75,876)	$ 60,652	$ 113,249
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON UNIT:
Basic and Diluted (in dollars per unit)	$ (0.62)	$ 0.50	$ 1
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted (in units)	122,579	121,546	113,433
Offshore pipeline transportation services
REVENUES:
Total revenues	$ 284,544	$ 318,239	$ 334,679
COSTS AND EXPENSES:
Cost of products and services sold	66,668	72,065	79,624
Sodium minerals and sulfur services
REVENUES:
Total revenues	1,174,434	462,622	171,503
COSTS AND EXPENSES:
Cost of products and services sold	912,491	333,918	91,443
Marine transportation
REVENUES:
Total revenues	219,937	205,287	213,021
COSTS AND EXPENSES:
Cost of products and services sold	172,527	154,606	142,551
Onshore facilities and transportation
REVENUES:
Total revenues	1,233,855	1,042,229	993,290
COSTS AND EXPENSES:
Cost of products and services sold	1,126,730	968,647	924,627
Onshore facilities and transportation | Onshore facilities and transportation product costs
COSTS AND EXPENSES:
Cost of products and services sold	1,037,688	866,458	823,524
Onshore facilities and transportation | Onshore facilities and transportation operating costs
COSTS AND EXPENSES:
Cost of products and services sold	$ 89,042	$ 102,189	$ 101,103

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (11,792)	$ 82,079	$ 111,082
Other comprehensive income (loss):
Decrease (increase) in benefit plan liability	1,543	(604)	0
Total Comprehensive income (loss)	(4,532)	82,043	113,249
Comprehensive loss attributable to non-controlling interests	5,717	568	2,167
Comprehensive income (loss) attributable to Genesis Energy, L.P.	$ (10,249)	$ 81,475	$ 111,082

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Previously Reported	Partners' Capital	Partners' CapitalPreviously Reported	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, 2015					109,979,000
Partners' capital, beginning balance at Dec. 31, 2015	$ 2,020,751		$ 2,029,101				$ (8,350)		$ 0
PARTNERS’ CAPITAL:
Net income (loss)	111,082		113,249		$ 0		(2,167)		0
Cash distributions to partners, net	(310,039)		(310,039)		0		0		0
Cash contributions from noncontrolling interests	236		0		$ 0		236		0
Issuance of common units for cash, net (in units)					8,000,000
Issuance of common units for cash, net	298,020		298,020				0		0
Other comprehensive income (loss)	0
Partners' capital, ending balance (in units) at Dec. 31, 2016					117,979,000
Partners' capital, ending balance at Dec. 31, 2016	2,120,050		2,130,331				(10,281)		0
PARTNERS’ CAPITAL:
Net income (loss)	82,079		82,647		$ 0		(568)		0
Cash distributions to partners, net	(321,875)		(321,875)		0		0		0
Cash contributions from noncontrolling interests	2,770		0		$ 0		2,770		0
Issuance of common units for cash, net (in units)					4,600,000
Issuance of common units for cash, net	140,513		140,513				0		0
Other comprehensive income (loss)	(604)		0		$ 0		0		(604)
Distributions to preferred unitholders	$ (5,469)		(5,469)		0		0		0
Partners' capital, ending balance (in units) at Dec. 31, 2017	122,579,218					122,579,000
Partners' capital, ending balance at Dec. 31, 2017	$ 2,017,464	$ 2,017,464		$ 2,026,147				$ (8,079)		$ (604)
PARTNERS’ CAPITAL:
Net income (loss)	(11,792)		(6,075)		0		(5,717)		0
Cash distributions to partners, net	(257,416)		(257,416)		0		0		0
Cash contributions from noncontrolling interests	2,592		0		0		2,592		0
Other comprehensive income (loss)	1,543		0		0		0		1,543
Distributions to preferred unitholders	$ (68,307)		(68,307)		$ 0		0		0
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:
Accumulated distributions to preferred unitholders	$ (69,800)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (11,792)	$ 82,079	$ 111,082
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	313,190	252,480	222,196
Provision for leased items no longer in use	0	12,589	0
Gain on sale of assets	(42,264)	(40,311)	0
Impairment expense	126,282	0	0
Amortization and write-off of debt issuance costs and premium or discount	12,165	13,103	10,138
Amortization of unearned income and initial direct costs on direct financing leases	(13,035)	(13,747)	(14,395)
Payments received under direct financing leases	20,668	20,668	20,672
Equity in earnings of investments in equity investees	(43,626)	(51,046)	(47,944)
Cash distributions of earnings of equity investees	42,735	47,316	50,281
Non-cash effect of long-term incentive compensation plans	3,941	(5,775)	6,558
Deferred and other tax benefits	663	(4,060)	2,142
Unrealized (gains) losses on derivative transactions	(11,795)	10,943	1,287
Other, net	(4,941)	(10,839)	11,385
Net changes in components of operating assets and liabilities, net of acquisitions (See Note 16)	(2,152)	10,156	(90,650)
Net cash provided by operating activities	390,039	323,556	282,752
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(195,367)	(250,593)	(463,100)
Cash distributions received from equity investees—return of investment	28,979	35,582	36,939
Investments in equity investees	(3,018)	(4,647)	0
Acquisitions	0	(1,325,759)	(25,394)
Contributions in aid of construction costs	0	124	13,374
Proceeds from asset sales	310,099	85,722	3,609
Other, net	0	0	(151)
Net cash used in (provided by) investing activities	140,693	(1,459,571)	(434,723)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	980,700	1,458,700	1,115,800
Repayments on senior secured credit facility	(1,109,800)	(1,637,700)	(952,600)
Proceeds from issuance of senior unsecured notes	0	1,000,000	0
Proceeds from issuance of Class A convertible preferred units, net	0	726,419	0
Repayment of senior unsecured notes	(145,170)	(204,830)	0
Debt issuance costs	(242)	(25,913)	(1,578)
Issuance of common units for cash, net	0	140,513	298,020
Contributions from noncontrolling interests	2,592	2,770	236
Distributions to common unitholders	(257,416)	(321,875)	(310,039)
Other, net	(137)	(57)	(1,734)
Net cash provided by (used in) financing activities	(529,473)	1,138,027	148,105
Net increase (decrease) in cash and cash equivalents	1,259	2,012	(3,866)
Cash and cash equivalents at beginning of period	9,041	7,029	10,895
Cash and cash equivalents at end of period	$ 10,300	$ 9,041	$ 7,029

Organization

Organization	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization We are a growth-oriented master limited partnership 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, Alkali Business, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, soda ash production, marketing and selling business (our "Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand. We report the results of our Alkali Business in our sodium minerals and sulfur services segment, which includes our Alkali Business as well as our legacy refinery services operations. We currently manage our businesses through four divisions that constitute our reportable segments: • Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico; • Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, 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 CO2; 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, 2018
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, 2018 and 2017 and our results of operations, statements of comprehensive income(loss), changes in partners’ capital and cash flows for the years ended December 31, 2018 , 2017 and 2016 . 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 have no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. 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. Accretion of the discount increases the liability and is recorded to expense. See Note 7 . Direct Financing Leasing Arrangements For our direct financing leases, 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. We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit rating and financial position of the lessee. See Note 8 . Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives. 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 are amortizing our customer and supplier relationships, contract agreements, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are being amortized on a straight-line basis. 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 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 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 As a result of our acquisition of our Alkali Business, we now sponsor a defined benefit plan. 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 or 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 4 for more information regarding our acquisition accounting and recording of acquisition costs. Recent and Proposed Accounting Pronouncements We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. The adoption date for our material equity method investment in the Poseidon Oil Pipeline Company, LLC will follow the non-public business entity adoption date of January 1, 2019 for its stand-alone financial statements. Refer to Note 3 for further details. In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements. In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. We have reviewed the practical expedients that are available to facilitate the adoption process. We have elected to take the "package" of practical expedients set out in the standard, which must be elected together. The items within the package stipulate that an entity need not reassess: (1) if expired or existing contracts contain leases, (2) lease classification for previously-assessed leases under ASC 840, and (3) initial direct costs for existing leases. We have also elected to adopt the practical expedient relating to the separation of lease and non-lease components as well as the easement and right of way expedient. Finally we have elected to utilize the optional transition method which allows the company to only apply the new lease standard at the date of adoption while comparative periods will be presented under the previous lease guidance. We will not adopt the hindsight practical expedient. As a result of adopting the new lease standard, we expect an impact on our consolidated balance sheet from the recognition of a right-of-use asset and the corresponding lease liability of less than $250 million . We do not expect a material impact to partners capital as a result of our transition adjustment. 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 and $15.6 million from operating cash flows to investing cash flows for the years ended December 31, 2017 and 2016, respectively. 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, 2018
Revenue Recognition [Abstract]
Revenue Recognition	Revenue Recognition Adoption of ASC 606 and its related Transition Effects The modified retrospective method of adoption required us to apply ASC 606 to all new revenue contracts entered into after January 1, 2018 and revenue contracts that were not completed as of January 1, 2018. Our consolidated revenues for periods prior to January 1, 2018 were not revised and the cumulative effect of our adoption of ASC 606 was recorded as an adjustment to partners' capital at January 1, 2018. Based on this application, the following adjustments were made to our consolidated balance sheet as of January 1, 2018: December 31, 2017 Adjustments January 1, 2018 ASSETS Accounts receivable - trade, net $ 495,449 $ (48,028 ) $ 447,421 Inventories 88,653 5,138 93,791 Other assets, net of amortization 56,628 59,204 115,832 LIABILITIES AND CAPITAL Other long-term liabilities 256,571 19,864 276,435 Partners' capital 2,026,147 (3,550 ) 2,022,597 Current Impact of New Revenue Recognition Guidance The tables below summarize the impact of adoption on our consolidated balance sheet and statement of operations as of and for the year ended December 31, 2018: As of December 31, 2018 Consolidated Balance Sheet As Reported Without adoption of ASC 606 Effect of Change Increase/(Decrease) ASSETS Accounts receivable-trade, net $ 323,462 $ 371,490 $ (48,028 ) Inventories 73,531 69,367 4,164 Other Assets, net of amortization 121,707 49,466 72,241 LIABILITIES AND CAPITAL Other Long-Term Liabilities 259,198 232,927 26,271 Partners' Capital 1,690,799 1,688,693 2,106 Year ended December 31, 2018 Consolidated Statement of Operations As Reported Without adoption of ASC 606 Effect of Change Increase/(Decrease) Offshore pipeline transportation services $ 284,544 $ 277,915 $ 6,629 Sodium minerals and sulfur services 1,174,434 1,071,634 102,800 Marine transportation 219,937 219,937 — Onshore facilities and transportation 1,233,855 1,233,855 — Total revenues 2,912,770 2,803,341 109,429 Onshore facilities and transportation product costs 1,037,688 1,037,688 — Onshore facilities and transportation operating costs 89,042 89,042 — Marine transportation operating costs 172,527 172,527 — Sodium minerals and sulfur services operating costs 912,491 808,718 103,773 Offshore pipeline transportation operating costs 66,668 66,668 — OPERATING INCOME 170,248 164,592 5,656 The effects of changes pursuant to ASC 606 in the tables above are attributable to our offshore pipeline transportation services operating segment and our sodium minerals and sulfur services operating segment. In our offshore pipeline transportation services segment, we have certain contracts with customers that contain tiered pricing structures that are dependent upon reaching certain cumulative milestones of throughput volumes on our pipelines. In addition, we have a contract that contains fixed and variable consideration for us to stand ready to provide firm reservation capacity for a fixed minimum quantity on our pipeline. Pursuant to the new guidance, we have allocated our estimated total transaction price over the life of the contract to the related performance obligation and recognized the effects in our Consolidated Financial Statements. In our sodium minerals and sulfur services operating segment, specifically our legacy refinery services business, we have two distinct performance obligations, including the completion of our refinery sulfur removal process, for which we receive in-kind consideration, and our sale of NaHS to our customers. As a result, we have recorded revenue and the related cost of sales in the Consolidated Financial Statements for the year ended December 31, 2018 for services performed for the in-kind consideration for our services. Further discussion of our performance obligations by type and segment are below. Revenue from Contracts with Customers The following table reflects the disaggregation of our revenues by major category for the year ended December 31, 2018: Year Ended 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 services revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, 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 loading/unloading services, among others, primarily on a per barrel fee basis. Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff and some contain minimum throughput provisions which reset within one year . We recognize revenues for transportation and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible transportation and other services are recognized over time as the product is delivered to the agreed upon delivery point or at the point of receipt because they specifically relate to our efforts to transfer the distinct services. Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or regulated tariff pricing. 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 January 1, 2018 and December 31, 2018: Contract Assets Contract Liabilities Non-Current Non-Current Balance at January 1, 2018 $ 59,204 $ 19,864 Balance at December 31, 2018 72,241 26,271 During the year ended December 31, 2018, there were no balances that were previously classified as contract liabilities at the beginning of the period that were recognized as revenues. Accounts receivable-trade, net does not include consideration received in kind from our refinery services process. We did not have any contract modifications during the period that would affect our contract asset and liability balances. Transaction Price Allocations to Remaining Performance Obligations We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance obligations as of December 31, 2018. 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 Marine Transportation Onshore Facilities and Transportation 2019 $ 74,200 $ 27,010 $ 65,436 2020 51,256 20,128 57,090 2021 34,562 — 20,139 2022 22,828 — 4,283 2023 12,076 — — Thereafter 123,371 — — Total $ 318,293 $ 47,138 $ 146,948

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2018
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 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, 2016 . 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 2017 2016 Pro forma consolidated financial operating results: Revenues $ 2,549,438 $ 2,498,293 Net Income Attributable to Genesis Energy, L.P. 108,392 156,700 Net Income Available to Common Unitholders 42,768 91,076 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 $ 1.00 Pro forma net income per common unit, basic and dilutive $ 0.35 $ 0.80 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, 2018
Accounts Receivable, Net, Current [Abstract]
Receivables	Receivables Accounts receivable – trade, net consisted of the following: December 31, 2018 2017 Accounts receivable - trade $ 330,855 $ 503,917 Allowance for doubtful accounts (7,393 ) (8,468 ) Accounts receivable - trade, net $ 323,462 $ 495,449 The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2018 2017 2016 Balance at beginning of period $ 8,468 $ 6,505 $ 1,446 Charged to costs and expenses, net of recoveries 31 2,001 6,463 Amounts written off (1,106 ) (38 ) (1,404 ) Balance at end of period $ 7,393 $ 8,468 $ 6,505

Inventories

Inventories	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Inventories	Inventories The major components of inventories were as follows: December 31, 2018 2017 Petroleum products $ 12,203 $ 8,731 Crude oil 8,379 29,873 Caustic soda 10,372 5,755 NaHS 12,400 8,277 Raw materials - Alkali Operations 5,952 4,550 Work-in-process - Alkali Operations 2,322 7,355 Finished goods, net - Alkali Operations 11,402 14,075 Materials and supplies, net - Alkali Operations 10,490 10,030 Other 11 7 Total $ 73,531 $ 88,653 Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were recorded below cost by approximately $1.0 million as of December 31, 2018 and were no t recorded below cost as of December 31, 2017 ; therefore we reduced the value of inventory in our Consolidated Financial Statements for this difference.

Fixed Assets and Asset Retireme

Fixed Assets and Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 Crude oil pipelines and natural gas pipelines and related assets $ 2,918,285 $ 3,028,657 Alkali facilities, machinery, and equipment 533,924 497,601 Onshore facilities, machinery, and equipment 639,023 692,364 Transportation equipment 20,102 21,483 Marine vessels 951,597 918,953 Land, buildings and improvements 222,242 223,186 Office equipment, furniture and fixtures 20,505 18,112 Construction in progress 94,025 151,768 Other 41,155 48,891 Fixed assets, at cost 5,440,858 5,601,015 Less: Accumulated depreciation (1,023,825 ) (734,986 ) Net fixed assets $ 4,417,033 $ 4,866,029 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 (5,538 ) (1,513 ) Mineral leaseholds, net $ 560,481 $ 564,506 Depreciation expense was $286.0 million , $226.0 million and $194.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Depletion expense was $4.0 million and $1.5 million for the years ended December 31, 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. 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. During 2017, we sold certain non-core natural gas gathering and platform assets in the Gulf of Mexico included in our offshore pipeline transportation services segment, as well as certain onshore terminal facilities in West Texas included in our onshore facilities and transportation segment. These sales resulted in total gains on asset sales of $40.3 million for the year ended December 31, 2017 recorded in Gains on assets sales in the Consolidated Statements of Operations. 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, 2016 $ 213,726 Accretion expense 11,008 Revisions in timing and estimated costs of AROs 7,146 Acquisitions 131 Divestitures (7,649 ) Settlements (26,415 ) Other 240 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 At December 31, 2018 and December 31, 2017 , $67.5 million and $20.9 million are included as current in "Accrued liabilities" on our Consolidated Balance Sheet, respectively. Revisions in timing and estimated costs during 2018 is 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: 2019 $ 9,928 2020 $ 10,997 2021 $ 9,313 2022 $ 9,892 2023 $ 10,586 Certain of our unconsolidated affiliates have AROs recorded at December 31, 2018 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, 2018
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, 2018 and 2017 , the unamortized differences in carrying value totaled $366.4 million and $382.4 million , respectively. We amortize the differences in carrying value as a change in equity earnings. In the first quarter of 2016, we purchased the remaining 50% interest in Deepwater Gateway, LLC for approximately $26.0 million (including adjustments for working capital), increasing our ownership interest to 100% . Consequently, we now consolidate Deepwater Gateway, LLC instead of accounting for our interest under the equity method. The following table presents information included in our Consolidated Financial Statements related to our equity investees. Year Ended December 31, 2018 2017 2016 Genesis’ share of operating earnings $ 59,255 $ 66,814 $ 63,805 Amortization of differences attributable to Genesis' carrying value of equity investments (15,629 ) (15,768 ) (15,861 ) Net equity in earnings $ 43,626 $ 51,046 $ 47,944 Distributions received $ 71,714 $ 82,898 $ 87,220 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) including the effects of the change in our ownership interest due to the Deepwater acquisition as previously discussed: December 31, 2018 2017 BALANCE SHEET DATA: Assets Current assets $ 34,005 $ 34,381 Fixed assets, net 346,864 362,214 Other assets 15,469 14,927 Total assets $ 396,338 $ 411,522 Liabilities and equity Current liabilities $ 18,897 $ 23,289 Other liabilities 250,742 249,610 Equity 126,699 138,623 Total liabilities and equity $ 396,338 $ 411,522 Year Ended December 31, 2018 2017 2016 INCOME STATEMENT DATA: Revenues $ 180,056 $ 191,078 $ 193,038 Operating Income $ 129,160 $ 139,604 $ 122,836 Net Income $ 115,669 $ 134,479 $ 118,175 Poseidon's revolving credit facility

Net Investment in Direct Financ

Net Investment in Direct Financing Leases	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Net Investment in Direct Financing Leases	Net Investment in Direct Financing Leases Our direct financing leases include a lease of the Northeast Jackson Dome (“NEJD”) Pipeline. Under the terms of the agreement, we are paid quarterly payments, which commenced August 2008 . These quarterly payments are fixed at approximately $20.7 million per year 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 interests in the NEJD Pipeline to the lessee for a nominal payment. There are requirements in our leases that would provide credit support should the credit rating of our lessee fall to certain levels, and at December 31, 2018, the required credit support has been provided. The following table lists the components of the net investment in direct financing leases: December 31, 2018 2017 Total minimum lease payments to be received $ 195,280 $ 215,884 Unamortized initial direct costs 801 950 Less unearned income (70,735 ) (83,918 ) Net investment in direct financing leases 125,346 132,916 Less current portion (included in other current assets) (8,421 ) (7,633 ) Long-term portion of net investment in direct financing leases $ 116,925 $ 125,283 At December 31, 2018 , minimum lease payments to be received for each of the five succeeding fiscal years are $20.7 million

Intangible Assets, Goodwill and

Intangible Assets, Goodwill and Other Assets	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 : December 31, 2018 December 31, 2017 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Sodium Minerals and Sulfur Services: Customer relationships 5 $ 94,654 $ 94,654 $ — $ 94,654 $ 92,493 $ 2,161 Licensing agreements 6 38,678 38,678 — 38,678 36,528 2,150 Non-compete agreement 3 800 356 444 800 89 711 Segment total 134,132 133,688 444 134,132 129,110 5,022 Onshore Facilities & Transportation: Customer relationships 5 35,430 35,123 307 35,430 35,082 348 Intangibles associated with lease 15 13,260 5,407 7,853 13,260 4,933 8,327 Segment total 48,690 40,530 8,160 48,690 40,015 8,675 Marine contract intangible 5 27,000 17,100 9,900 27,000 11,700 15,300 Offshore pipeline contract intangibles 19 158,101 28,431 129,670 158,101 20,109 137,992 Other 5 30,947 16,519 14,428 28,900 13,483 15,417 Total $ 398,870 $ 236,268 $ 162,602 $ 396,823 $ 214,417 $ 182,406 The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services. The onshore facilities and transportation lease relates to a terminal facility in Shreveport, Louisiana. The marine contract intangible 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 identified in connection with our purchase price allocation surrounding the Enterprise Acquisition. 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. Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. The onshore facilities and transportation lease, marine contract, offshore pipeline contract intangibles and other intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $21.8 million , $23.6 million and $24.3 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2019 2020 2021 2022 2023 Sodium Minerals and Sulfur Services: Non Compete 267 177 — — — Onshore Facilities & Transportation: Customer relationships 39 38 37 35 34 Intangibles associated with lease 474 474 474 474 474 Marine contract intangibles 5,400 4,500 — — — Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 3,153 3,132 2,011 1,853 1,568 Total $ 17,654 $ 16,642 $ 10,843 $ 10,683 $ 10,397 Goodwill The carrying amount of goodwill in sodium minerals and sulfur services was $301.9 million in December 31, 2018 and 2017 . 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, 2018 2017 CO 2 volumetric production payments, net of amortization $ 890 $ 2,175 Deferred marine charges, net (1) 28,175 30,246 Contract assets (2) 72,241 — Other deferred costs and deposits 20,401 24,207 Other assets, net of amortization $ 121,707 $ 56,628 (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 are being amortized on a units-of-production method. We recorded amortization of $1.3 million in 2018 , $1.3 million in 2017 and $3.9 million in 2016

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Debt At December 31, 2018 and 2017 , our obligations under debt arrangements consisted of the following: December 31, 2018 December 31, 2017 Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Senior secured credit facility $ 970,100 $ — $ 970,100 $ 1,099,200 $ — 1,099,200 5.750% senior unsecured notes — — — 145,170 1,303 143,867 6.750% senior unsecured notes 750,000 12,763 737,237 750,000 16,077 733,923 6.000% senior unsecured notes 400,000 4,624 395,376 400,000 5,691 394,309 5.625% senior unsecured notes 350,000 4,820 345,180 350,000 5,717 344,283 6.500% senior unsecured notes 550,000 8,241 541,759 550,000 9,462 540,538 6.250% senior unsecured notes 450,000 $ 7,189 442,811 450,000 8,002 441,998 Total long-term debt $ 3,470,100 $ 37,637 $ 3,432,463 $ 3,744,370 $ 46,252 $ 3,698,118 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Consolidated Balance Sheet) were $10.8 million and $14.1 million as of December 31, 2018 and December 31, 2017, respectively. Senior Secured Credit Facility In October 2018, we amended our credit agreement to, among other things, make certain technical amendments related to the sale of our Powder River Basin midstream assets. 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, 2018 , the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% 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, 2018 , our letter of credit rate was 2.75% . • 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, 2018 ). • 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 . 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, 2018 , we had $970.1 million borrowed under our credit facility, with $17.8 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 $1.2 million was outstanding at December 31, 2018 . 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, 2018 was $728.7 million . 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 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 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 indenture 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, 2018 , we were in compliance with the financial covenants contained in our credit facility and indenture.

Partners' Capital, Mezzanine Eq

Partners' Capital, Mezzanine Equity and Distributions	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Partners' Capital, Mezzanine Equity and Distributions	Partners’ Capital, Mezzanine Equity and Distributions At December 31, 2018 , 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. 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 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 distributions in 2019 , 2018 and 2017 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2016 4th Quarter February 14, 2017 $ 0.7100 $ 83,765 2017 1st Quarter May 15, 2017 $ 0.7200 $ 88,257 2nd Quarter August 14, 2017 $ 0.7225 $ 88,563 3rd Quarter November 14, 2017 $ 0.5000 $ 61,290 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 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. On July 27, 2016 , we issued 8,000,000 Class A common units in a public offering at a price of $37.90 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $298.5 million from that offering. We used those proceeds to repay a portion of the borrowings outstanding under our credit facility. The new common units issued in 2017 and 2016 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 July 2016 Public 8,000 $ 37.90 $ 303,200 $ (4,748 ) $ 298,452 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 have 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 elect to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We have elected to pay all distributions from inception through the quarter ending December 31, 2018 with additional preferred units. For each quarter ending after March 1, 2019, we must pay 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, 2017 162,234 $ 5,469 2018 January 2018 February 14, 2018 490,252 $ 16,526 April 2018 May 15, 2018 500,976 $ 16,888 July 2018 August 14, 2018 511,934 $ 17,257 October 2018 November 14, 2018 523,132 $ 17,635 The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2018: 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 Net income(loss) attributable to common unitholders is reduced by Preferred Unit distributions that accumulated during the period. During 2018, net income attributable to common unitholders was reduced by $69.8 million as a result of distributions that accumulated during the period. With respect to our Class A Convertible Preferred Units relating to the fourth quarter of 2018, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the issuance of an additional 534,576 Class A Convertible Preferred Units. This PIK amount equates to a distribution of $0.7374 per Class A Convertible Preferred Unit for the 2018 Quarter, or $2.9496 annualized. These distributions were paid on February 14, 2019 to preferred unitholders holders of record at the close of business January 31, 2019.

Net Income (Loss) Per Common Un

Net Income (Loss) Per Common Unit	12 Months Ended
	Dec. 31, 2018
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, 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 year ended December 31, 2018 , the effect of the assumed conversion of the 24,438,022 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 2018 2017 2016 Net Income (Loss) Attributable to Genesis Energy L.P. $ (6,075 ) $ 82,647 $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (69,801 ) (21,995 ) — Net Income (Loss) Available to Common Unitholders $ (75,876 ) $ 60,652 $ 113,249 Weighted Average Outstanding Units 122,579 121,546 113,433 Basic and Diluted Net Income (Loss) per Common Unit $ (0.62 ) $ 0.50 $ 1.00

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information Our operations consist of four operating segments (see Note 1 for discussion of segment reporting change): • 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 and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total 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 Year Ended December 31, 2016 Segment Margin (a) $ 336,620 $ 79,508 $ 83,364 $ 70,079 $ 569,571 Capital expenditures (b) $ 46,277 $ 2,274 $ 316,638 $ 78,804 $ 443,993 Revenues: External customers $ 332,514 $ 180,665 $ 993,103 $ 206,211 $ 1,712,493 Intersegment (c) 2,165 (9,162 ) 187 6,810 $ — Total revenues of reportable segments $ 334,679 $ 171,503 $ 993,290 $ 213,021 $ 1,712,493 Total assets by reportable segment were as follows: December 31, 2018 December 31, 2017 December 31, 2016 Offshore pipeline transportation 2,359,013 2,486,803 2,575,335 Sodium minerals and sulfur services 1,844,845 1,848,188 395,043 Onshore facilities and transportation 1,431,910 1,927,976 1,875,403 Marine transportation 800,243 824,777 813,722 Other assets 43,060 49,737 43,089 Total consolidated assets $ 6,479,071 $ 7,137,481 $ 5,702,592 (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. During the year ended December 31, 2016, capital expenditures in our offshore pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in Deepwater Gateway. (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 2018 2017 2016 Total Segment Margin $ 712,758 $ 594,543 $ 569,571 Corporate general and administrative expenses (64,683 ) (60,029 ) (40,905 ) Depreciation, depletion, amortization and accretion (317,186 ) (262,021 ) (230,563 ) Interest expense (229,191 ) (176,762 ) (139,947 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (28,088 ) (31,852 ) (39,276 ) Non-cash items not included in Segment Margin 9,698 (14,305 ) (3,221 ) Cash payments from direct financing leases in excess of earnings (7,633 ) (6,921 ) (6,277 ) Loss on extinguishment of debt (3,339 ) (6,242 ) — Differences in timing of cash receipts for certain contractual arrangements (2) 6,629 17,540 13,253 Gain on sales of assets 42,264 40,311 — Other, net — (2,985 ) (6,044 ) Non-cash provision for leased items no longer in use 476 (12,589 ) — Income tax expense (1,498 ) 3,959 (3,342 ) Impairment expense (126,282 ) — — Net income (loss) attributable to Genesis Energy, L.P. $ (6,075 ) $ 82,647 $ 113,249 (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 Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties Transactions with related parties were as follows: Year Ended December 31, 2018 2017 2016 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ 1,233 $ 2,820 $ 3,097 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,557 12,357 10,844 Revenues from product sales to ANSAC 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) 994 986 1,007 Charges for services from ANSAC 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, 2018 , 2017 and 2016 reflect $8.6 million , $8.4 million and $7.9 million , respectively, of fees we earned through the provision of services under that agreement. At December 31, 2018 , and 2017 , Poseidon Oil Pipeline Company, LLC owed us $2.4 million and $2.2 million , respectively, 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. Net sales to ANSAC were $373.6 million and $124.5 million for the years ended December 31, 2018 and 2017 . The costs charged to us by ANSAC, included in operating costs, were $5.3 million and $2.2 million for the year ended December 31, 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, 2018 and 2017 , our receivables from and payables to ANSAC were: December 31 December 31 2018 2017 Receivables: ANSAC $ 60,594 $ 74,490 Payables: ANSAC $ 815 $ 1,223 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.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (Increase) decrease in: Accounts receivable $ 130,573 $ (140,948 ) $ (9,859 ) Inventories 20,963 49,055 (54,361 ) Deferred charges (5,826 ) (3,622 ) (3,902 ) Other current assets 9,337 (410 ) 3,059 Increase (decrease) in: Accounts payable (130,991 ) 97,569 (17,426 ) Accrued liabilities (26,208 ) 8,512 (8,161 ) Net changes in components of operating assets and liabilities $ (2,152 ) $ 10,156 $ (90,650 ) Payments of interest and commitment fees were $228.3 million , $168.3 million and $157.4 million during the years ended December 31, 2018 , 2017 and 2016 , respectively. We capitalized interest of $3.4 million , $15.0 million and $26.6 million during the years ended December 31, 2018 , 2017 and 2016 . During the years ended December 31, 2018 , 2017 and 2016 , we paid taxes of $0.2 million , $1.0 million and $1.3 million . At December 31, 2018 , 2017 and 2016 , we had incurred liabilities for fixed and intangible asset additions totaling $9.4 million , $39.7 million and $33.7 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, 2018
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 2018 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 2018 , we granted 28,484 phantom units with tandem DERs at a weighted average grant 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. During 2016 , we granted 339,584 phantom units with tandem DERs at a weighted average grant date fair value of $30.71 per unit. The phantom units granted during 2018 were made only to directors. Awards to management and other key employees during 2018 were made under the 2018 LTIP plan, and were non-equity awards. The phantom units granted during 2017 and 2016 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 2016 and 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 2019 and 2020 , respectively. 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, 2017 239,837 $ 34.81 $ 8,349 582,375 $ 34.73 $ 20,228 Granted 28,484 $ 22.12 630 — $ — — Forfeited (17,073 ) $ 31.46 (537 ) (67,266 ) $ 33.49 (2,253 ) Settled (55,309 ) $ 44.92 (2,484 ) (137,103 ) $ 45.40 (6,224 ) Unvested at December 31, 2018 195,939 $ 30.40 $ 5,958 378,006 $ 31.09 $ 11,751 At December 31, 2018 , we estimated the unrecognized compensation cost of our phantom awards to be approximately $0.6 million to be recognized over a weighted average period of approximately 0.8 years. We recorded a charge of $2.1 million and a credit of $3.4 million to compensation expense for the years ended December 31, 2018 and 2017 , respectively. Our liability for these awards totaled $3.3 million and $3.2 million at December 31, 2018 and 2017 , respectively. Equity-Based Compensation Plan Expense Equity-based compensation expense during the three years ended December 31, 2018 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2018 2017 2016 Onshore facilities and transportation operating costs $ 140 $ (1,137 ) $ 1,688 Marine transportation operating costs 183 (483 ) 1,089 Sodium minerals and sulfur services operating costs 112 (533 ) 547 Offshore pipeline operating costs 297 (152 ) 681 General and administrative expenses 1,239 (2,272 ) 4,575 Total $ 1,971 $ (4,577 ) $ 8,580

Major Customers and Credit Risk

Major Customers and Credit Risk	12 Months Ended
	Dec. 31, 2018
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. During 2018 , 2017 and 2016 our largest customer was Shell Oil Company, which accounted for 11% , 13% , and 12% of total revenues, respectively. The revenues from Shell Oil Company in all three years relate primarily to our onshore facilities and transportation operations. In addition, 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.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2018
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, in 2018 we entered into 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 cost of sales. At December 31, 2018 , 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) 56 — Weighted average contract price per bbl $ 53.11 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 293 234 Weighted average contract price per bbl $ 49.85 $ 49.37 Natural gas swaps: Contract volumes (10,000 MMBTU) 502 — Weighted average price differential per MMBTU $ 0.62 — Natural gas futures: Contract volumes (10,000 MMBTU) 137 590 Weighted average contract price per MMBTU $ 3.53 $ 2.91 Diesel futures: Contract volumes (1,000 bbls) 2 2 Weighted average contract price per bbl $ 1.89 $ 1.85 NYM RBOB Gas futures: Contract volumes (42,000 gallons) 2 1 Weighted average contract price per gallon $ 1.35 $ 1.29 Fuel oil futures: Contract volumes (1,000 bbls) 382 40 Weighted average contract price per bbl $ 51.41 $ 49.94 Crude oil options: Contract volumes (1,000 bbls) 26 — Weighted average premium received $ 2.66 $ — 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, 2018 and 2017 : Fair Value of Derivative Assets and Liabilities Fair Value Consolidated Balance Sheets Location December 31, 2018 December 31, 2017 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 3,431 $ 505 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1,361 ) (505 ) Net amount of assets presented in the Consolidated Balance Sheets $ 2,070 $ — Natural Gas Swap (undesignated hedge) Current Assets - Other 1,274 — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 469 $ 54 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (44 ) (54 ) Net amount of assets presented in the Consolidated Balance Sheets $ 425 $ — Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (40,840 ) $ (45,209 ) 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) $ (1,361 ) $ (1,203 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,361 1,203 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (44 ) $ (863 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 44 338 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ (525 ) (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, 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). As of December 31, 2017 , we had a net broker receivable of approximately $1.0 million (consisting of initial margin of $1.3 million decreased by $0.3 million of variation margin). At December 31, 2018 and December 31, 2017 , 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, 2018 , the fair value of this embedded derivative was a liability of $40.8 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 Consolidated Statements of Operations Location 2018 2017 2016 Commodity derivatives—futures and call options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ (544 ) $ 5,116 $ (13,195 ) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs 3,914 (1,314 ) (5,847 ) Total commodity derivatives $ 3,370 $ 3,802 $ (19,042 ) Natural Gas Swap Sodium minerals and sulfur services operating costs 1,906 $ — $ — Preferred Distribution Rate Reset Election ( Note 20 ) Other Income (Expense) $ 8,360 $ (10,472 ) $ — We have no derivative contracts with credit contingent features.

Fair-Value Measurements

Fair-Value Measurements	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . December 31, 2018 December 31, 2017 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 3,900 $ 1,274 $ — $ 559 $ — $ — Liabilities $ (1,405 ) $ (125 ) $ — $ (2,066 ) $ — $ — Preferred Distribution Rate Reset Election $ — $ — $ (40,840 ) $ — $ — $ (45,209 ) Rollforward of Level 3 Fair Value Measurements The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3: Balance as of December 31, 2016 — Initial valuation of Preferred Distribution Rate Reset Election (34,450 ) Net Loss for the period including earnings (10,472 ) Allocation of Distribution Paid-in-kind (287 ) Balance as of December 31, 2017 (45,209 ) Net gain for the period included in earnings 8,360 Allocation of Distribution Paid-in-kind (3,991 ) Balance as of December 31, 2018 $ (40,840 ) 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, 2018 . 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, 2018 our senior unsecured notes had a carrying value of $2.5 billion and a fair value of $2.3 billion , compared to $2.6 billion and $2.7 billion , respectively at December 31, 2017 . 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, 2018
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans Upon acquisition of our Alkali Business in 2017, we now sponsor a defined benefit plan. We account for the Alkali Business benefit 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 benefit 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. The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2018 2017 Change in benefit obligation: Benefit Obligation, beginning of year $ 22,530 $ — Service Cost 5,153 1,749 Interest Cost 862 267 Actuarial (Gain) Loss (3,816 ) 992 Benefits Paid (218 ) (56 ) Acquisition of Alkali Business — 19,578 Benefit Obligation, end of year 24,511 22,530 Change in plan assets: Fair Value of Plan Assets, beginning of year 13,306 — Actual Return (loss) on Plan Assets (1,300 ) 647 Employer Contributions 3,928 2,250 Benefits Paid (218 ) (56 ) Acquisition of Alkali Business — 10,465 Fair Value of Plan assets, end of year 15,716 13,306 Funded Status at end of period $ (8,795 ) $ (9,224 ) Amounts recognized in the Consolidated Balance Sheet: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (8,795 ) (9,224 ) Net Liability at end of year $ (8,795 ) $ (9,224 ) Amounts recognized in accumulated other comprehensive income (loss): Net actuarial (gain) loss (939 ) 604 Amounts recognized in accumulated other comprehensive income ( loss:) $ (939 ) $ 604 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 2019 Contributions by Employer $ 3,550 Future Expected Benefit Payments 2019 $ 587 2020 816 2021 962 2022 1,109 2023 1,265 2024-2028 8,465 Net Periodic Pension Costs- The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2018 2017 Service Cost $ 5,153 $ 1,749 Interest Cost 862 267 Expected Return on Assets (973 ) (259 ) $ 5,042 $ 1,757 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 benefit 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 benefit 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, 2018 December 31, 2017 Discount Rate 4.62 % 3.90 % Expected Long-term Rate of Return 6.41 % 6.28 % 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 3.90% . Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy established for our Pension Plan. The target allocation is designed to achieve long term objectives of return, mitigating risk, and considering expected cash flows. Our Pension Plan asset allocations at December 31, 2018 by asset category are as follows: December 31, 2018 Target % Actual % Equity securities 41-60% 51 % Fixed income securities 40-50% 41 % Other 0-10% 8 % A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents 506 — — $ 506 260 — — $ 260 Equity securities 8,038 — — $ 8,038 2,518 — — $ 2,518 Mutual and other exchange traded funds 7,172 — — $ 7,172 10,528 — — $ 10,528 15,716 — — $ 15,716 13,306 — — $ 13,306

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments and Guarantees Our office lease for our corporate headquarters extends until October 31, 2022 . To transport products, we lease tractors, trailers and railcars. In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS and caustic soda. Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput. We have no minimum volumetric or financial requirements remaining on our pipeline lease. The future minimum rental payments under all non-cancelable operating leases as of December 31, 2018 , were as follows (in thousands): Office Space Transportation Equipment Terminals and Tanks Total 2019 $ 4,197 $ 27,547 $ 14,298 $ 46,042 2020 4,119 24,642 10,594 39,355 2021 3,298 19,536 7,840 30,674 2022 2,692 18,113 6,653 27,458 2023 961 17,290 9,378 27,629 2024 and thereafter 3,735 45,390 77,104 126,229 Total minimum lease obligations $ 19,002 $ 152,518 $ 125,867 $ 297,387 Total operating lease expense from our continuing operations was as follows (in thousands): Year Ended December 31, 2018 $ 30,798 Year Ended December 31, 2017 $ 36,933 Year Ended December 31, 2016 $ 41,906 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, 2018
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, 2018 2017 2016 Current: Federal $ — $ — $ — State 810 100 1,200 Total current income tax expense $ 810 $ 100 $ 1,200 Deferred: Federal $ 114 $ (5,530 ) $ 1,862 State 574 1,471 280 Total deferred income tax expense (benefit) $ 688 $ (4,059 ) $ 2,142 Total income tax expense (benefit) $ 1,498 $ (3,959 ) $ 3,342 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, 2018 2017 Deferred tax assets: Net operating loss carryforwards $ 11,491 $ 9,506 Total long-term deferred tax asset 11,491 9,506 Valuation allowances (1,758 ) (1,285 ) Total deferred tax assets $ 9,733 $ 8,221 Deferred tax liabilities: Long-term: Fixed assets $ (2,893 ) $ (3,896 ) Intangible assets (18,209 ) (15,797 ) Other (1,207 ) (441 ) Total long-term liability (22,309 ) (20,134 ) Total deferred tax liabilities $ (22,309 ) $ (20,134 ) Total net deferred tax liability $ (12,576 ) $ (11,913 ) 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, 2018 2017 2016 Income(loss) from operations before income taxes $ (10,294 ) $ 78,120 $ 114,424 Partnership income not subject to federal income tax 10,824 (77,704 ) (109,111 ) Income subject to federal income taxes $ 530 $ 416 $ 5,313 Tax expense at federal statutory rate $ 111 $ 146 $ 1,860 State income taxes, net of federal tax 1,285 1,396 949 Return to provision, federal and state (128 ) (163 ) (198 ) Other 230 (68 ) 731 Re-measurement of deferred taxes due to enacted tax rate change — (5,270 ) — Income tax expense (benefit) $ 1,498 $ (3,959 ) $ 3,342 Effective tax rate on income from operations before income taxes (15 )% (5 )% 3 % At December 31, 2018 , 2017 and 2016, we had no uncertain tax positions.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Quarterly Financial Information (Unaudited)	Quarterly Financial Data (Unaudited) The table below summarizes our unaudited quarterly financial data for 2018 and 2017 . 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 income (loss) per common unit: Net income (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 2017 Quarters First Second Third Fourth Revenues from continuing operations $ 415,491 $ 406,723 $ 486,114 $ 720,049 Operating income $ 52,597 $ 61,447 $ 43,100 $ 63,407 Net income $ 26,938 $ 33,580 $ 6,160 $ 15,401 Net loss attributable to noncontrolling interest $ 152 $ 153 $ 152 $ 111 Net income attributable to Genesis Energy, L.P. $ 27,090 $ 33,733 $ 6,312 $ 15,512 Basic and diluted net income (loss) per common unit: Net income (loss) per common unit $ 0.23 $ 0.28 $ 0.01 $ (0.01 ) Cash distributions per common unit (1) $ 0.7100 $ 0.7200 $ 0.7225 $ 0.5000 (1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2018
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 Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 11 for additional information regarding our consolidated debt obligations. On September 23, 2019, the Company announced the expansion of its Granger facilities which included designating the subsidiaries that hold our Alkali business (such subsidiaries, collectively, 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 25 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 2017 and the condensed consolidating statements of operations and cash flows for the years ended December 31, 2018 and 2017 included in footnote 25 of the Notes to Consolidated Financial Statements 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. It is noted that the statements of operations and cash flows for the year ended December 31, 2016 were not retrospectively adjusted as we did not acquire our Alkali business until the third quarter of 2017. All other information in the 2018 Form 10-K remains unchanged. The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors: 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 is related to our pension held within our Non-Guarantor Subsidiaries. Condensed Consolidating Balance Sheet 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 ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 5,230 $ 3,805 $ — $ 9,041 Other current assets 50 — 407,821 219,177 (56 ) 626,992 Total current assets 56 — 413,051 222,982 (56 ) 636,033 Fixed Assets, at cost — — 4,832,639 768,376 — 5,601,015 Less: Accumulated depreciation — — (692,193 ) (42,793 ) — (734,986 ) Net fixed assets — — 4,140,446 725,583 — 4,866,029 Mineral Leaseholds, net of accumulated depletion — — — 564,506 — 564,506 Goodwill — — 325,046 — — 325,046 Other assets, net 14,083 — 372,201 132,470 (154,437 ) 364,317 Advances to affiliates 3,808,712 — — 86,023 (3,894,735 ) — Equity investees — — 381,550 — — 381,550 Investments in subsidiaries 2,689,861 — 1,431,550 — (4,121,411 ) — Total assets $ 6,512,712 $ — $ 7,063,844 $ 1,731,564 $ (8,170,639 ) $ 7,137,481 LIABILITIES AND CAPITAL Current liabilities $ 46,086 $ — $ 307,673 $ 102,761 $ (256 ) $ 456,264 Senior secured credit facility 1,099,200 — — — — 1,099,200 Senior unsecured notes, net of debt issuance costs 2,598,918 — — — — 2,598,918 Deferred tax liabilities — — 11,913 — — 11,913 Advances from affiliates — — 3,894,627 — (3,894,627 ) — Other liabilities 45,210 — 166,705 198,946 (154,290 ) 256,571 Total liabilities 3,789,414 — 4,380,918 301,707 (4,049,173 ) 4,422,866 Mezzanine Capital Class A Convertible Preferred Units 697,151 — — — — 697,151 Partners' capital 2,026,147 — 2,682,926 1,438,540 (4,121,466 ) 2,026,147 Accumulated other comprehensive income (loss) — — — (604 ) — (604 ) Noncontrolling interests — — — (8,079 ) — (8,079 ) Total liabilities, mezzanine capital and partners’ capital $ 6,512,712 $ — $ 7,063,844 $ 1,731,564 $ (8,170,639 ) $ 7,137,481 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 services $ — $ — $ 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 benefit (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 services $ — $ — $ 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, depletion 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 expense — — 3,928 31 — 3,959 NET INCOME 82,647 — 276,497 40,770 (317,835 ) 82,079 Net loss attributable to noncontrolling interests — — — 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 Operations Year Ended December 31, 2016 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 services $ — $ — $ 334,679 $ — $ — $ 334,679 Sodium minerals and sulfur services — — 171,389 7,873 (7,759 ) 171,503 Marine transportation — — 213,021 — — 213,021 Onshore facilities and transportation — — 972,794 20,496 — 993,290 Total revenues — — 1,691,883 28,369 (7,759 ) 1,712,493 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 923,567 1,060 — 924,627 Marine transportation operating costs — — 142,551 — — 142,551 Sodium minerals and sulfur services operating costs — — 90,711 8,491 (7,759 ) 91,443 Offshore pipeline transportation operating costs — — 68,791 10,833 — 79,624 General and administrative — — 45,625 — — 45,625 Depreciation and amortization — — 219,696 2,500 — 222,196 Total costs and expenses — — 1,490,941 22,884 (7,759 ) 1,506,066 OPERATING INCOME — — 200,942 5,485 — 206,427 Equity in earnings of equity investees — — 47,944 — — 47,944 Equity in earnings of subsidiaries 253,048 — (6,744 ) — (246,304 ) — Interest expense, net (139,799 ) — 14,407 (14,555 ) — (139,947 ) Income before income taxes 113,249 — 256,549 (9,070 ) (246,304 ) 114,424 Income tax expense — — (3,337 ) (5 ) — (3,342 ) NET INCOME $ 113,249 $ — $ 253,212 $ (9,075 ) $ (246,304 ) $ 111,082 Net loss attributable to noncontrolling interest $ — $ — $ — $ 2,167 $ — 2,167 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ — $ — $ — $ — $ — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 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 asset sales — — 310,099 — — 310,099 Net cash provided by (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 assets 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, including premium 1,000,000 — — — — 1,000,000 Proceeds from issuance of Series A convertible preferred 726,419 — — — — 726,419 Repayment of senior unsecured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Intercompany transfers — — 1,169,781 1,313,000 (2,482,781 ) — Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Distributions to partners/owners (321,875 ) — (321,875 ) (17,500 ) 339,375 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 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 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 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 $ 179,853 $ — $ 382,734 $ 9,586 $ (289,421 ) $ 282,752 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (463,100 ) — — (463,100 ) Cash distributions received from equity investees - return of investment — — 36,939 — — 36,939 Investments in equity investees (298,020 ) — — — 298,020 — Acquisitions — — (25,394 ) — — (25,394 ) Intercompany transfers (31,436 ) — — — 31,436 — Repayments on loan to non-guarantor subsidiary — — 6,113 — (6,113 ) — Contributions in aid of construction costs — — 13,374 — — 13,374 Proceeds from asset sales — — 3,609 — — 3,609 Other, net — — (151 ) — — (151 ) Net cash (used in) provided by investing activities (329,456 ) — (428,610 ) — 323,343 (434,723 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,115,800 — — — — 1,115,800 Repayments on senior secured credit facility (952,600 ) — — — — (952,600 ) Debt issuance costs (1,578 ) — — — — (1,578 ) Distribution to partners/owners (310,039 ) — (310,039 ) — 310,039 (310,039 ) Contributions from noncontrolling interest — — — 236 — 236 Issuance of common units for cash, net 298,020 — 298,020 — (298,020 ) 298,020 Intercompany transfers — — 57,701 (26,264 ) (31,437 ) — Other, net — — (1,734 ) 14,504 (14,504 ) (1,734 ) Net cash provided by (used in) financing activities 149,603 — 43,948 (11,524 ) (33,922 ) 148,105 Net decrease in cash and cash equivalents — — (1,928 ) (1,938 ) — (3,866 ) Cash and cash equivalents at beginning of period 6 — 8,288 2,601 — 10,895 Cash and cash equivalents at end of period $ 6 $ — $ 6,360 $ 663 $ — $ 7,029

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 and our results of operations, statements of comprehensive income(loss), changes in partners’ capital and cash flows for the years ended December 31, 2018 , 2017 and 2016 . 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 and Cash Equivalents	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 have no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.
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
Direct Financing Leasing Arrangements	Direct Financing Leasing Arrangements For our direct financing leases, 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.
Intangible and Other Assets	Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives. 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 are amortizing our customer and supplier relationships, contract agreements, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are being amortized on a straight-line basis. 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 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
Revenue Recognition	Revenue Recognition 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 services revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, 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 loading/unloading services, among others, primarily on a per barrel fee basis. Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff and some contain minimum throughput provisions which reset within one year . We recognize revenues for transportation and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible transportation and other services are recognized over time as the product is delivered to the agreed upon delivery point or at the point of receipt because they specifically relate to our efforts to transfer the distinct services. Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or regulated tariff pricing. 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. The effects of changes pursuant to ASC 606 in the tables above are attributable to our offshore pipeline transportation services operating segment and our sodium minerals and sulfur services operating segment. Adoption of ASC 606 and its related Transition Effects 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, 2018. 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.
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 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 As a result of our acquisition of our Alkali Business, we now sponsor a defined benefit plan. 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 or loss.
Business Acquisitions	Business Acquisitions
Recent and Proposed Accounting Pronouncements	Recent and Proposed Accounting Pronouncements We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. The adoption date for our material equity method investment in the Poseidon Oil Pipeline Company, LLC will follow the non-public business entity adoption date of January 1, 2019 for its stand-alone financial statements. Refer to Note 3 for further details. In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements. In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. We have reviewed the practical expedients that are available to facilitate the adoption process. We have elected to take the "package" of practical expedients set out in the standard, which must be elected together. The items within the package stipulate that an entity need not reassess: (1) if expired or existing contracts contain leases, (2) lease classification for previously-assessed leases under ASC 840, and (3) initial direct costs for existing leases. We have also elected to adopt the practical expedient relating to the separation of lease and non-lease components as well as the easement and right of way expedient. Finally we have elected to utilize the optional transition method which allows the company to only apply the new lease standard at the date of adoption while comparative periods will be presented under the previous lease guidance. We will not adopt the hindsight practical expedient. As a result of adopting the new lease standard, we expect an impact on our consolidated balance sheet from the recognition of a right-of-use asset and the corresponding lease liability of less than $250 million . We do not expect a material impact to partners capital as a result of our transition adjustment. 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 and $15.6 million from operating cash flows to investing cash flows for the years ended December 31, 2017 and 2016, respectively. 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, 2018
Revenue Recognition [Abstract]
Schedule of Impact on Consolidated Balance Sheet and Statement of Operations	Adoption of ASC 606 and its related Transition Effects The modified retrospective method of adoption required us to apply ASC 606 to all new revenue contracts entered into after January 1, 2018 and revenue contracts that were not completed as of January 1, 2018. Our consolidated revenues for periods prior to January 1, 2018 were not revised and the cumulative effect of our adoption of ASC 606 was recorded as an adjustment to partners' capital at January 1, 2018. Based on this application, the following adjustments were made to our consolidated balance sheet as of January 1, 2018: December 31, 2017 Adjustments January 1, 2018 ASSETS Accounts receivable - trade, net $ 495,449 $ (48,028 ) $ 447,421 Inventories 88,653 5,138 93,791 Other assets, net of amortization 56,628 59,204 115,832 LIABILITIES AND CAPITAL Other long-term liabilities 256,571 19,864 276,435 Partners' capital 2,026,147 (3,550 ) 2,022,597 Current Impact of New Revenue Recognition Guidance The tables below summarize the impact of adoption on our consolidated balance sheet and statement of operations as of and for the year ended December 31, 2018: As of December 31, 2018 Consolidated Balance Sheet As Reported Without adoption of ASC 606 Effect of Change Increase/(Decrease) ASSETS Accounts receivable-trade, net $ 323,462 $ 371,490 $ (48,028 ) Inventories 73,531 69,367 4,164 Other Assets, net of amortization 121,707 49,466 72,241 LIABILITIES AND CAPITAL Other Long-Term Liabilities 259,198 232,927 26,271 Partners' Capital 1,690,799 1,688,693 2,106 Year ended December 31, 2018 Consolidated Statement of Operations As Reported Without adoption of ASC 606 Effect of Change Increase/(Decrease) Offshore pipeline transportation services $ 284,544 $ 277,915 $ 6,629 Sodium minerals and sulfur services 1,174,434 1,071,634 102,800 Marine transportation 219,937 219,937 — Onshore facilities and transportation 1,233,855 1,233,855 — Total revenues 2,912,770 2,803,341 109,429 Onshore facilities and transportation product costs 1,037,688 1,037,688 — Onshore facilities and transportation operating costs 89,042 89,042 — Marine transportation operating costs 172,527 172,527 — Sodium minerals and sulfur services operating costs 912,491 808,718 103,773 Offshore pipeline transportation operating costs 66,668 66,668 — OPERATING INCOME 170,248 164,592 5,656
Schedule of Disaggregation of Revenue	The following table reflects the disaggregation of our revenues by major category for the year ended December 31, 2018: Year Ended 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 January 1, 2018 and December 31, 2018: Contract Assets Contract Liabilities Non-Current Non-Current Balance at January 1, 2018 $ 59,204 $ 19,864 Balance at December 31, 2018 72,241 26,271
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 Marine Transportation Onshore Facilities and Transportation 2019 $ 74,200 $ 27,010 $ 65,436 2020 51,256 20,128 57,090 2021 34,562 — 20,139 2022 22,828 — 4,283 2023 12,076 — — Thereafter 123,371 — — Total $ 318,293 $ 47,138 $ 146,948

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2018
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 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 2017 2016 Pro forma consolidated financial operating results: Revenues $ 2,549,438 $ 2,498,293 Net Income Attributable to Genesis Energy, L.P. 108,392 156,700 Net Income Available to Common Unitholders 42,768 91,076 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 $ 1.00 Pro forma net income per common unit, basic and dilutive $ 0.35 $ 0.80

Receivables (Tables)

Receivables (Tables)	12 Months Ended
	Dec. 31, 2018
Accounts Receivable, Net, Current [Abstract]
Schedule of Trade Accounts Receivables Net	Accounts receivable – trade, net consisted of the following: December 31, 2018 2017 Accounts receivable - trade $ 330,855 $ 503,917 Allowance for doubtful accounts (7,393 ) (8,468 ) Accounts receivable - trade, net $ 323,462 $ 495,449
Schedule of Allowance For Doubtful Accounts	The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2018 2017 2016 Balance at beginning of period $ 8,468 $ 6,505 $ 1,446 Charged to costs and expenses, net of recoveries 31 2,001 6,463 Amounts written off (1,106 ) (38 ) (1,404 ) Balance at end of period $ 7,393 $ 8,468 $ 6,505

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Schedule of Major Components of Inventories	The major components of inventories were as follows: December 31, 2018 2017 Petroleum products $ 12,203 $ 8,731 Crude oil 8,379 29,873 Caustic soda 10,372 5,755 NaHS 12,400 8,277 Raw materials - Alkali Operations 5,952 4,550 Work-in-process - Alkali Operations 2,322 7,355 Finished goods, net - Alkali Operations 11,402 14,075 Materials and supplies, net - Alkali Operations 10,490 10,030 Other 11 7 Total $ 73,531 $ 88,653

Fixed Assets and Asset Retire_2

Fixed Assets and Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Fixed Assets And Asset Retirement Obligations [Abstract]
Schedule of Fixed Assets	Fixed assets consisted of the following: December 31, 2018 2017 Crude oil pipelines and natural gas pipelines and related assets $ 2,918,285 $ 3,028,657 Alkali facilities, machinery, and equipment 533,924 497,601 Onshore facilities, machinery, and equipment 639,023 692,364 Transportation equipment 20,102 21,483 Marine vessels 951,597 918,953 Land, buildings and improvements 222,242 223,186 Office equipment, furniture and fixtures 20,505 18,112 Construction in progress 94,025 151,768 Other 41,155 48,891 Fixed assets, at cost 5,440,858 5,601,015 Less: Accumulated depreciation (1,023,825 ) (734,986 ) Net fixed assets $ 4,417,033 $ 4,866,029
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 (5,538 ) (1,513 ) Mineral leaseholds, net $ 560,481 $ 564,506
Schedule of Change in Asset Retirement Obligation	A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2016 $ 213,726 Accretion expense 11,008 Revisions in timing and estimated costs of AROs 7,146 Acquisitions 131 Divestitures (7,649 ) Settlements (26,415 ) Other 240 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
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: 2019 $ 9,928 2020 $ 10,997 2021 $ 9,313 2022 $ 9,892 2023 $ 10,586

Equity Investees (Tables)

Equity Investees (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 Genesis’ share of operating earnings $ 59,255 $ 66,814 $ 63,805 Amortization of differences attributable to Genesis' carrying value of equity investments (15,629 ) (15,768 ) (15,861 ) Net equity in earnings $ 43,626 $ 51,046 $ 47,944 Distributions received $ 71,714 $ 82,898 $ 87,220
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) including the effects of the change in our ownership interest due to the Deepwater acquisition as previously discussed: December 31, 2018 2017 BALANCE SHEET DATA: Assets Current assets $ 34,005 $ 34,381 Fixed assets, net 346,864 362,214 Other assets 15,469 14,927 Total assets $ 396,338 $ 411,522 Liabilities and equity Current liabilities $ 18,897 $ 23,289 Other liabilities 250,742 249,610 Equity 126,699 138,623 Total liabilities and equity $ 396,338 $ 411,522
Schedule of Operations For Equity Investees	Year Ended December 31, 2018 2017 2016 INCOME STATEMENT DATA: Revenues $ 180,056 $ 191,078 $ 193,038 Operating Income $ 129,160 $ 139,604 $ 122,836 Net Income $ 115,669 $ 134,479 $ 118,175

Net Investment in Direct Fina_2

Net Investment in Direct Financing Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Components Of Net Investment In Direct Financing Leases	The following table lists the components of the net investment in direct financing leases: December 31, 2018 2017 Total minimum lease payments to be received $ 195,280 $ 215,884 Unamortized initial direct costs 801 950 Less unearned income (70,735 ) (83,918 ) Net investment in direct financing leases 125,346 132,916 Less current portion (included in other current assets) (8,421 ) (7,633 ) Long-term portion of net investment in direct financing leases $ 116,925 $ 125,283

Intangible Assets, Goodwill a_2

Intangible Assets, Goodwill and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	The following table reflects the components of intangible assets being amortized at December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Sodium Minerals and Sulfur Services: Customer relationships 5 $ 94,654 $ 94,654 $ — $ 94,654 $ 92,493 $ 2,161 Licensing agreements 6 38,678 38,678 — 38,678 36,528 2,150 Non-compete agreement 3 800 356 444 800 89 711 Segment total 134,132 133,688 444 134,132 129,110 5,022 Onshore Facilities & Transportation: Customer relationships 5 35,430 35,123 307 35,430 35,082 348 Intangibles associated with lease 15 13,260 5,407 7,853 13,260 4,933 8,327 Segment total 48,690 40,530 8,160 48,690 40,015 8,675 Marine contract intangible 5 27,000 17,100 9,900 27,000 11,700 15,300 Offshore pipeline contract intangibles 19 158,101 28,431 129,670 158,101 20,109 137,992 Other 5 30,947 16,519 14,428 28,900 13,483 15,417 Total $ 398,870 $ 236,268 $ 162,602 $ 396,823 $ 214,417 $ 182,406
Schedule of Estimated Amortization Expense	The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2019 2020 2021 2022 2023 Sodium Minerals and Sulfur Services: Non Compete 267 177 — — — Onshore Facilities & Transportation: Customer relationships 39 38 37 35 34 Intangibles associated with lease 474 474 474 474 474 Marine contract intangibles 5,400 4,500 — — — Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 3,153 3,132 2,011 1,853 1,568 Total $ 17,654 $ 16,642 $ 10,843 $ 10,683 $ 10,397
Schedule of Other Assets	Other assets consisted of the following: December 31, 2018 2017 CO 2 volumetric production payments, net of amortization $ 890 $ 2,175 Deferred marine charges, net (1) 28,175 30,246 Contract assets (2) 72,241 — Other deferred costs and deposits 20,401 24,207 Other assets, net of amortization $ 121,707 $ 56,628 (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, 2018
Debt Disclosure [Abstract]
Schedule of Obligations Under Debt Arrangements	At December 31, 2018 and 2017 , our obligations under debt arrangements consisted of the following: December 31, 2018 December 31, 2017 Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value Senior secured credit facility $ 970,100 $ — $ 970,100 $ 1,099,200 $ — 1,099,200 5.750% senior unsecured notes — — — 145,170 1,303 143,867 6.750% senior unsecured notes 750,000 12,763 737,237 750,000 16,077 733,923 6.000% senior unsecured notes 400,000 4,624 395,376 400,000 5,691 394,309 5.625% senior unsecured notes 350,000 4,820 345,180 350,000 5,717 344,283 6.500% senior unsecured notes 550,000 8,241 541,759 550,000 9,462 540,538 6.250% senior unsecured notes 450,000 $ 7,189 442,811 450,000 8,002 441,998 Total long-term debt $ 3,470,100 $ 37,637 $ 3,432,463 $ 3,744,370 $ 46,252 $ 3,698,118 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Consolidated Balance Sheet) were $10.8 million and $14.1 million as of December 31, 2018 and December 31, 2017, respectively.
Schedule of Summary of Applicable Redemption Periods	A summary of the applicable redemption periods is provided in the table below. 2022 Notes 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

Partners' Capital, Mezzanine _2

Partners' Capital, Mezzanine Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of Paid Distributions	We paid distributions in 2019 , 2018 and 2017 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2016 4th Quarter February 14, 2017 $ 0.7100 $ 83,765 2017 1st Quarter May 15, 2017 $ 0.7200 $ 88,257 2nd Quarter August 14, 2017 $ 0.7225 $ 88,563 3rd Quarter November 14, 2017 $ 0.5000 $ 61,290 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
Schedule of New Common Units Issued to the Public For Cash	The new common units issued in 2017 and 2016 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 July 2016 Public 8,000 $ 37.90 $ 303,200 $ (4,748 ) $ 298,452
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, 2017 162,234 $ 5,469 2018 January 2018 February 14, 2018 490,252 $ 16,526 April 2018 May 15, 2018 500,976 $ 16,888 July 2018 August 14, 2018 511,934 $ 17,257 October 2018 November 14, 2018 523,132 $ 17,635
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, 2018: 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

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2016 Net Income (Loss) Attributable to Genesis Energy L.P. $ (6,075 ) $ 82,647 $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (69,801 ) (21,995 ) — Net Income (Loss) Available to Common Unitholders $ (75,876 ) $ 60,652 $ 113,249 Weighted Average Outstanding Units 122,579 121,546 113,433 Basic and Diluted Net Income (Loss) per Common Unit $ (0.62 ) $ 0.50 $ 1.00

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
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, 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 Year Ended December 31, 2016 Segment Margin (a) $ 336,620 $ 79,508 $ 83,364 $ 70,079 $ 569,571 Capital expenditures (b) $ 46,277 $ 2,274 $ 316,638 $ 78,804 $ 443,993 Revenues: External customers $ 332,514 $ 180,665 $ 993,103 $ 206,211 $ 1,712,493 Intersegment (c) 2,165 (9,162 ) 187 6,810 $ — Total revenues of reportable segments $ 334,679 $ 171,503 $ 993,290 $ 213,021 $ 1,712,493 Total assets by reportable segment were as follows: December 31, 2018 December 31, 2017 December 31, 2016 Offshore pipeline transportation 2,359,013 2,486,803 2,575,335 Sodium minerals and sulfur services 1,844,845 1,848,188 395,043 Onshore facilities and transportation 1,431,910 1,927,976 1,875,403 Marine transportation 800,243 824,777 813,722 Other assets 43,060 49,737 43,089 Total consolidated assets $ 6,479,071 $ 7,137,481 $ 5,702,592 (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. During the year ended December 31, 2016, capital expenditures in our offshore pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in Deepwater Gateway. (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 2018 2017 2016 Total Segment Margin $ 712,758 $ 594,543 $ 569,571 Corporate general and administrative expenses (64,683 ) (60,029 ) (40,905 ) Depreciation, depletion, amortization and accretion (317,186 ) (262,021 ) (230,563 ) Interest expense (229,191 ) (176,762 ) (139,947 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (28,088 ) (31,852 ) (39,276 ) Non-cash items not included in Segment Margin 9,698 (14,305 ) (3,221 ) Cash payments from direct financing leases in excess of earnings (7,633 ) (6,921 ) (6,277 ) Loss on extinguishment of debt (3,339 ) (6,242 ) — Differences in timing of cash receipts for certain contractual arrangements (2) 6,629 17,540 13,253 Gain on sales of assets 42,264 40,311 — Other, net — (2,985 ) (6,044 ) Non-cash provision for leased items no longer in use 476 (12,589 ) — Income tax expense (1,498 ) 3,959 (3,342 ) Impairment expense (126,282 ) — — Net income (loss) attributable to Genesis Energy, L.P. $ (6,075 ) $ 82,647 $ 113,249 (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_2

Transactions with Related Parties (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Schedule of Transactions With Related Parties	ransactions with related parties were as follows: Year Ended December 31, 2018 2017 2016 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ 1,233 $ 2,820 $ 3,097 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,557 12,357 10,844 Revenues from product sales to ANSAC 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) 994 986 1,007 Charges for services from ANSAC 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, 2018 and 2017 , our receivables from and payables to ANSAC were: December 31 December 31 2018 2017 Receivables: ANSAC $ 60,594 $ 74,490 Payables: ANSAC $ 815 $ 1,223 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.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (Increase) decrease in: Accounts receivable $ 130,573 $ (140,948 ) $ (9,859 ) Inventories 20,963 49,055 (54,361 ) Deferred charges (5,826 ) (3,622 ) (3,902 ) Other current assets 9,337 (410 ) 3,059 Increase (decrease) in: Accounts payable (130,991 ) 97,569 (17,426 ) Accrued liabilities (26,208 ) 8,512 (8,161 ) Net changes in components of operating assets and liabilities $ (2,152 ) $ 10,156 $ (90,650 )

Equity-Based Compensation Pla_2

Equity-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2017 239,837 $ 34.81 $ 8,349 582,375 $ 34.73 $ 20,228 Granted 28,484 $ 22.12 630 — $ — — Forfeited (17,073 ) $ 31.46 (537 ) (67,266 ) $ 33.49 (2,253 ) Settled (55,309 ) $ 44.92 (2,484 ) (137,103 ) $ 45.40 (6,224 ) Unvested at December 31, 2018 195,939 $ 30.40 $ 5,958 378,006 $ 31.09 $ 11,751
Schedule of Equity-Based Compensation Expense	Equity-based compensation expense during the three years ended December 31, 2018 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2018 2017 2016 Onshore facilities and transportation operating costs $ 140 $ (1,137 ) $ 1,688 Marine transportation operating costs 183 (483 ) 1,089 Sodium minerals and sulfur services operating costs 112 (533 ) 547 Offshore pipeline operating costs 297 (152 ) 681 General and administrative expenses 1,239 (2,272 ) 4,575 Total $ 1,971 $ (4,577 ) $ 8,580

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivatives Entered Into Hedge Inventory or Fixed Price Purchase Commitments	At December 31, 2018 , 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) 56 — Weighted average contract price per bbl $ 53.11 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 293 234 Weighted average contract price per bbl $ 49.85 $ 49.37 Natural gas swaps: Contract volumes (10,000 MMBTU) 502 — Weighted average price differential per MMBTU $ 0.62 — Natural gas futures: Contract volumes (10,000 MMBTU) 137 590 Weighted average contract price per MMBTU $ 3.53 $ 2.91 Diesel futures: Contract volumes (1,000 bbls) 2 2 Weighted average contract price per bbl $ 1.89 $ 1.85 NYM RBOB Gas futures: Contract volumes (42,000 gallons) 2 1 Weighted average contract price per gallon $ 1.35 $ 1.29 Fuel oil futures: Contract volumes (1,000 bbls) 382 40 Weighted average contract price per bbl $ 51.41 $ 49.94 Crude oil options: Contract volumes (1,000 bbls) 26 — Weighted average premium received $ 2.66 $ —
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, 2018 and 2017 : Fair Value of Derivative Assets and Liabilities Fair Value Consolidated Balance Sheets Location December 31, 2018 December 31, 2017 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 3,431 $ 505 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1,361 ) (505 ) Net amount of assets presented in the Consolidated Balance Sheets $ 2,070 $ — Natural Gas Swap (undesignated hedge) Current Assets - Other 1,274 — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 469 $ 54 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (44 ) (54 ) Net amount of assets presented in the Consolidated Balance Sheets $ 425 $ — Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (40,840 ) $ (45,209 ) 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) $ (1,361 ) $ (1,203 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,361 1,203 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (44 ) $ (863 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 44 338 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ (525 ) (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 Consolidated Statements of Operations Location 2018 2017 2016 Commodity derivatives—futures and call options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ (544 ) $ 5,116 $ (13,195 ) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs 3,914 (1,314 ) (5,847 ) Total commodity derivatives $ 3,370 $ 3,802 $ (19,042 ) Natural Gas Swap Sodium minerals and sulfur services operating costs 1,906 $ — $ — Preferred Distribution Rate Reset Election ( Note 20 ) Other Income (Expense) $ 8,360 $ (10,472 ) $ —

Fair-Value Measurements (Tables

Fair-Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . December 31, 2018 December 31, 2017 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 3,900 $ 1,274 $ — $ 559 $ — $ — Liabilities $ (1,405 ) $ (125 ) $ — $ (2,066 ) $ — $ — Preferred Distribution Rate Reset Election $ — $ — $ (40,840 ) $ — $ — $ (45,209 )
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, 2016 — Initial valuation of Preferred Distribution Rate Reset Election (34,450 ) Net Loss for the period including earnings (10,472 ) Allocation of Distribution Paid-in-kind (287 ) Balance as of December 31, 2017 (45,209 ) Net gain for the period included in earnings 8,360 Allocation of Distribution Paid-in-kind (3,991 ) Balance as of December 31, 2018 $ (40,840 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 Change in benefit obligation: Benefit Obligation, beginning of year $ 22,530 $ — Service Cost 5,153 1,749 Interest Cost 862 267 Actuarial (Gain) Loss (3,816 ) 992 Benefits Paid (218 ) (56 ) Acquisition of Alkali Business — 19,578 Benefit Obligation, end of year 24,511 22,530 Change in plan assets: Fair Value of Plan Assets, beginning of year 13,306 — Actual Return (loss) on Plan Assets (1,300 ) 647 Employer Contributions 3,928 2,250 Benefits Paid (218 ) (56 ) Acquisition of Alkali Business — 10,465 Fair Value of Plan assets, end of year 15,716 13,306 Funded Status at end of period $ (8,795 ) $ (9,224 ) Amounts recognized in the Consolidated Balance Sheet: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (8,795 ) (9,224 ) Net Liability at end of year $ (8,795 ) $ (9,224 ) Amounts recognized in accumulated other comprehensive income (loss): Net actuarial (gain) loss (939 ) 604 Amounts recognized in accumulated other comprehensive income ( loss:) $ (939 ) $ 604
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 2019 Contributions by Employer $ 3,550 Future Expected Benefit Payments 2019 $ 587 2020 816 2021 962 2022 1,109 2023 1,265 2024-2028 8,465
Schedule of Components of Net Periodic Costs	The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2018 2017 Service Cost $ 5,153 $ 1,749 Interest Cost 862 267 Expected Return on Assets (973 ) (259 ) $ 5,042 $ 1,757
Schedule of Weighted Average Assumptions Used To Determine Benefit Obligation	The Alkali Business benefit 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, 2018 December 31, 2017 Discount Rate 4.62 % 3.90 % Expected Long-term Rate of Return 6.41 % 6.28 % 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 3.90% .
Schedule of Pension Plan Asset Allocations	Our Pension Plan asset allocations at December 31, 2018 by asset category are as follows: December 31, 2018 Target % Actual % Equity securities 41-60% 51 % Fixed income securities 40-50% 41 % Other 0-10% 8 % A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents 506 — — $ 506 260 — — $ 260 Equity securities 8,038 — — $ 8,038 2,518 — — $ 2,518 Mutual and other exchange traded funds 7,172 — — $ 7,172 10,528 — — $ 10,528 15,716 — — $ 15,716 13,306 — — $ 13,306

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments Under All Non-Cancelable Operating Leases	The future minimum rental payments under all non-cancelable operating leases as of December 31, 2018 , were as follows (in thousands): Office Space Transportation Equipment Terminals and Tanks Total 2019 $ 4,197 $ 27,547 $ 14,298 $ 46,042 2020 4,119 24,642 10,594 39,355 2021 3,298 19,536 7,840 30,674 2022 2,692 18,113 6,653 27,458 2023 961 17,290 9,378 27,629 2024 and thereafter 3,735 45,390 77,104 126,229 Total minimum lease obligations $ 19,002 $ 152,518 $ 125,867 $ 297,387
Schedule Total Operating Lease Expense	Total operating lease expense from our continuing operations was as follows (in thousands): Year Ended December 31, 2018 $ 30,798 Year Ended December 31, 2017 $ 36,933 Year Ended December 31, 2016 $ 41,906

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense (Benefit)	Our income tax (benefit) expense is as follows: Year Ended December 31, 2018 2017 2016 Current: Federal $ — $ — $ — State 810 100 1,200 Total current income tax expense $ 810 $ 100 $ 1,200 Deferred: Federal $ 114 $ (5,530 ) $ 1,862 State 574 1,471 280 Total deferred income tax expense (benefit) $ 688 $ (4,059 ) $ 2,142 Total income tax expense (benefit) $ 1,498 $ (3,959 ) $ 3,342
Schedule of Deferred Tax Assets And Liabilities	Deferred tax assets and liabilities consist of the following: December 31, 2018 2017 Deferred tax assets: Net operating loss carryforwards $ 11,491 $ 9,506 Total long-term deferred tax asset 11,491 9,506 Valuation allowances (1,758 ) (1,285 ) Total deferred tax assets $ 9,733 $ 8,221 Deferred tax liabilities: Long-term: Fixed assets $ (2,893 ) $ (3,896 ) Intangible assets (18,209 ) (15,797 ) Other (1,207 ) (441 ) Total long-term liability (22,309 ) (20,134 ) Total deferred tax liabilities $ (22,309 ) $ (20,134 ) Total net deferred tax liability $ (12,576 ) $ (11,913 )
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, 2018 2017 2016 Income(loss) from operations before income taxes $ (10,294 ) $ 78,120 $ 114,424 Partnership income not subject to federal income tax 10,824 (77,704 ) (109,111 ) Income subject to federal income taxes $ 530 $ 416 $ 5,313 Tax expense at federal statutory rate $ 111 $ 146 $ 1,860 State income taxes, net of federal tax 1,285 1,396 949 Return to provision, federal and state (128 ) (163 ) (198 ) Other 230 (68 ) 731 Re-measurement of deferred taxes due to enacted tax rate change — (5,270 ) — Income tax expense (benefit) $ 1,498 $ (3,959 ) $ 3,342 Effective tax rate on income from operations before income taxes (15 )% (5 )% 3 %

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Schedule of Summarized Unaudited Quarterly Financial Data	The table below summarizes our unaudited quarterly financial data for 2018 and 2017 . 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 income (loss) per common unit: Net income (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 2017 Quarters First Second Third Fourth Revenues from continuing operations $ 415,491 $ 406,723 $ 486,114 $ 720,049 Operating income $ 52,597 $ 61,447 $ 43,100 $ 63,407 Net income $ 26,938 $ 33,580 $ 6,160 $ 15,401 Net loss attributable to noncontrolling interest $ 152 $ 153 $ 152 $ 111 Net income attributable to Genesis Energy, L.P. $ 27,090 $ 33,733 $ 6,312 $ 15,512 Basic and diluted net income (loss) per common unit: Net income (loss) per common unit $ 0.23 $ 0.28 $ 0.01 $ (0.01 ) Cash distributions per common unit (1) $ 0.7100 $ 0.7200 $ 0.7225 $ 0.5000 (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, 2018
Condensed Financial Information Disclosure [Abstract]
Schedule of Condensed Consolidating Financial Statements	The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors: 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 is related to our pension held within our Non-Guarantor Subsidiaries. Condensed Consolidating Balance Sheet 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 ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 5,230 $ 3,805 $ — $ 9,041 Other current assets 50 — 407,821 219,177 (56 ) 626,992 Total current assets 56 — 413,051 222,982 (56 ) 636,033 Fixed Assets, at cost — — 4,832,639 768,376 — 5,601,015 Less: Accumulated depreciation — — (692,193 ) (42,793 ) — (734,986 ) Net fixed assets — — 4,140,446 725,583 — 4,866,029 Mineral Leaseholds, net of accumulated depletion — — — 564,506 — 564,506 Goodwill — — 325,046 — — 325,046 Other assets, net 14,083 — 372,201 132,470 (154,437 ) 364,317 Advances to affiliates 3,808,712 — — 86,023 (3,894,735 ) — Equity investees — — 381,550 — — 381,550 Investments in subsidiaries 2,689,861 — 1,431,550 — (4,121,411 ) — Total assets $ 6,512,712 $ — $ 7,063,844 $ 1,731,564 $ (8,170,639 ) $ 7,137,481 LIABILITIES AND CAPITAL Current liabilities $ 46,086 $ — $ 307,673 $ 102,761 $ (256 ) $ 456,264 Senior secured credit facility 1,099,200 — — — — 1,099,200 Senior unsecured notes, net of debt issuance costs 2,598,918 — — — — 2,598,918 Deferred tax liabilities — — 11,913 — — 11,913 Advances from affiliates — — 3,894,627 — (3,894,627 ) — Other liabilities 45,210 — 166,705 198,946 (154,290 ) 256,571 Total liabilities 3,789,414 — 4,380,918 301,707 (4,049,173 ) 4,422,866 Mezzanine Capital Class A Convertible Preferred Units 697,151 — — — — 697,151 Partners' capital 2,026,147 — 2,682,926 1,438,540 (4,121,466 ) 2,026,147 Accumulated other comprehensive income (loss) — — — (604 ) — (604 ) Noncontrolling interests — — — (8,079 ) — (8,079 ) Total liabilities, mezzanine capital and partners’ capital $ 6,512,712 $ — $ 7,063,844 $ 1,731,564 $ (8,170,639 ) $ 7,137,481 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 services $ — $ — $ 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 benefit (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 services $ — $ — $ 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, depletion 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 expense — — 3,928 31 — 3,959 NET INCOME 82,647 — 276,497 40,770 (317,835 ) 82,079 Net loss attributable to noncontrolling interests — — — 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 Operations Year Ended December 31, 2016 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 services $ — $ — $ 334,679 $ — $ — $ 334,679 Sodium minerals and sulfur services — — 171,389 7,873 (7,759 ) 171,503 Marine transportation — — 213,021 — — 213,021 Onshore facilities and transportation — — 972,794 20,496 — 993,290 Total revenues — — 1,691,883 28,369 (7,759 ) 1,712,493 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 923,567 1,060 — 924,627 Marine transportation operating costs — — 142,551 — — 142,551 Sodium minerals and sulfur services operating costs — — 90,711 8,491 (7,759 ) 91,443 Offshore pipeline transportation operating costs — — 68,791 10,833 — 79,624 General and administrative — — 45,625 — — 45,625 Depreciation and amortization — — 219,696 2,500 — 222,196 Total costs and expenses — — 1,490,941 22,884 (7,759 ) 1,506,066 OPERATING INCOME — — 200,942 5,485 — 206,427 Equity in earnings of equity investees — — 47,944 — — 47,944 Equity in earnings of subsidiaries 253,048 — (6,744 ) — (246,304 ) — Interest expense, net (139,799 ) — 14,407 (14,555 ) — (139,947 ) Income before income taxes 113,249 — 256,549 (9,070 ) (246,304 ) 114,424 Income tax expense — — (3,337 ) (5 ) — (3,342 ) NET INCOME $ 113,249 $ — $ 253,212 $ (9,075 ) $ (246,304 ) $ 111,082 Net loss attributable to noncontrolling interest $ — $ — $ — $ 2,167 $ — 2,167 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ — $ — $ — $ — $ — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 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 asset sales — — 310,099 — — 310,099 Net cash provided by (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 assets 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, including premium 1,000,000 — — — — 1,000,000 Proceeds from issuance of Series A convertible preferred 726,419 — — — — 726,419 Repayment of senior unsecured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Intercompany transfers — — 1,169,781 1,313,000 (2,482,781 ) — Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Distributions to partners/owners (321,875 ) — (321,875 ) (17,500 ) 339,375 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 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 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 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 $ 179,853 $ — $ 382,734 $ 9,586 $ (289,421 ) $ 282,752 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (463,100 ) — — (463,100 ) Cash distributions received from equity investees - return of investment — — 36,939 — — 36,939 Investments in equity investees (298,020 ) — — — 298,020 — Acquisitions — — (25,394 ) — — (25,394 ) Intercompany transfers (31,436 ) — — — 31,436 — Repayments on loan to non-guarantor subsidiary — — 6,113 — (6,113 ) — Contributions in aid of construction costs — — 13,374 — — 13,374 Proceeds from asset sales — — 3,609 — — 3,609 Other, net — — (151 ) — — (151 ) Net cash (used in) provided by investing activities (329,456 ) — (428,610 ) — 323,343 (434,723 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,115,800 — — — — 1,115,800 Repayments on senior secured credit facility (952,600 ) — — — — (952,600 ) Debt issuance costs (1,578 ) — — — — (1,578 ) Distribution to partners/owners (310,039 ) — (310,039 ) — 310,039 (310,039 ) Contributions from noncontrolling interest — — — 236 — 236 Issuance of common units for cash, net 298,020 — 298,020 — (298,020 ) 298,020 Intercompany transfers — — 57,701 (26,264 ) (31,437 ) — Other, net — — (1,734 ) 14,504 (14,504 ) (1,734 ) Net cash provided by (used in) financing activities 149,603 — 43,948 (11,524 ) (33,922 ) 148,105 Net decrease in cash and cash equivalents — — (1,928 ) (1,938 ) — (3,866 ) Cash and cash equivalents at beginning of period 6 — 8,288 2,601 — 10,895 Cash and cash equivalents at end of period $ 6 $ — $ 6,360 $ 663 $ — $ 7,029

Organization (Details)

Organization (Details)	Sep. 01, 2017USD ($)	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Aug. 14, 2017USD ($)
Business Acquisition [Line Items]
Limited liability company, ownership interest owned		100.00%
Payments to acquire business		$ 0	$ 1,325,759,000	$ 25,394,000
Number of divisions that constitute reportable segments | segment		4
Class A Convertible Preferred Stock Units
Business Acquisition [Line Items]
Private placement of convertible preferred units	$ 750,000,000
Class A Convertible Preferred Stock 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
Alkali Business | Class A Convertible Preferred Stock Units | Private Placement
Business Acquisition [Line Items]
Private placement of convertible preferred units	750,000,000
Alkali Business | 6.500% senior unsecured notes
Business Acquisition [Line Items]
Debt issued, aggregate principal amount	$ 550,000,000				$ 550,000,000

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2019
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets	$ 0	$ 0	$ 0
Reclassification from operating cash flows due to adoption of new accounting pronouncement	(390,039,000)	(323,556,000)	(282,752,000)
Reclassification to investing cash flows due to adoption of new accounting pronouncement	$ 140,693,000	(1,459,571,000)	(434,723,000)
Leases (ASC 840)
Summary Of Significant Accounting Policies [Line Items]
Lease right-of-use asset (less than)				$ 250,000,000
Lease liability (less than)				$ 250,000,000
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	15,600,000
Reclassification to investing cash flows due to adoption of new accounting pronouncement		$ 15,300,000	$ 15,600,000
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 services | Poseidon Oil Pipeline Company
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	64.00%
Offshore pipeline transportation services | Neptune Pipeline Company LLC
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	25.70%
Offshore pipeline transportation services | Odyssey Pipeline L.L.C.
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	29.00%

Revenue Recognition (Impact on

Revenue Recognition (Impact on Consolidated Balance Sheet and Statement of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Assets
Accounts receivable—trade, net	$ 323,462				$ 495,449				$ 323,462	$ 495,449		$ 447,421
Inventories	73,531				88,653				73,531	88,653		93,791
Other assets, net of amortization	121,707				56,628				121,707	56,628		115,832
Liabilities and equity
Other liabilities	259,198				256,571				259,198	256,571		276,435
Partners’ capital, common units	1,690,799				2,026,147				1,690,799	2,026,147		2,022,597
OPERATING INCOME
Total revenues									2,912,770
Operating Income	4,119	$ 46,148	$ 60,900	$ 59,081	$ 63,407	$ 43,100	$ 61,447	$ 52,597	170,248	$ 220,551	$ 206,427
Offshore pipeline transportation services
OPERATING INCOME
Total revenues									284,544
Cost of revenues									66,668
Sodium minerals and sulfur services
OPERATING INCOME
Total revenues									1,174,434
Cost of revenues									912,491
Marine transportation
OPERATING INCOME
Total revenues									219,937
Cost of revenues									172,527
Onshore facilities and transportation
OPERATING INCOME
Total revenues									1,233,855
Onshore facilities and transportation | Onshore facilities and transportation product costs
OPERATING INCOME
Cost of revenues									1,037,688
Onshore facilities and transportation | Onshore facilities and transportation operating costs
OPERATING INCOME
Cost of revenues									89,042
Effect of Change Increase/(Decrease)
OPERATING INCOME
Total revenues									109,429
Operating Income									5,656
Effect of Change Increase/(Decrease) | Offshore pipeline transportation services
OPERATING INCOME
Total revenues									6,629
Cost of revenues									0
Effect of Change Increase/(Decrease) | Sodium minerals and sulfur services
OPERATING INCOME
Total revenues									102,800
Cost of revenues									103,773
Effect of Change Increase/(Decrease) | Marine transportation
OPERATING INCOME
Total revenues									0
Cost of revenues									0
Effect of Change Increase/(Decrease) | Onshore facilities and transportation
OPERATING INCOME
Total revenues									0
Effect of Change Increase/(Decrease) | Onshore facilities and transportation | Onshore facilities and transportation product costs
OPERATING INCOME
Cost of revenues									0
Effect of Change Increase/(Decrease) | Onshore facilities and transportation | Onshore facilities and transportation operating costs
OPERATING INCOME
Cost of revenues									0
Accounting Standards Update 2014-09 | Adjustments
Assets
Accounts receivable—trade, net	371,490								371,490
Inventories	69,367								69,367
Other assets, net of amortization	49,466								49,466
Liabilities and equity
Other liabilities	232,927								232,927
Partners’ capital, common units	1,688,693								1,688,693
OPERATING INCOME
Total revenues									2,803,341
Operating Income									164,592
Accounting Standards Update 2014-09 | Adjustments | Offshore pipeline transportation services
OPERATING INCOME
Total revenues									277,915
Cost of revenues									66,668
Accounting Standards Update 2014-09 | Adjustments | Sodium minerals and sulfur services
OPERATING INCOME
Total revenues									1,071,634
Cost of revenues									808,718
Accounting Standards Update 2014-09 | Adjustments | Marine transportation
OPERATING INCOME
Total revenues									219,937
Cost of revenues									172,527
Accounting Standards Update 2014-09 | Adjustments | Onshore facilities and transportation
OPERATING INCOME
Total revenues									1,233,855
Accounting Standards Update 2014-09 | Adjustments | Onshore facilities and transportation | Onshore facilities and transportation product costs
OPERATING INCOME
Cost of revenues									1,037,688
Accounting Standards Update 2014-09 | Adjustments | Onshore facilities and transportation | Onshore facilities and transportation operating costs
OPERATING INCOME
Cost of revenues									89,042
Accounting Standards Update 2014-09 | Effect of Change Increase/(Decrease)
Assets
Accounts receivable—trade, net	(48,028)								(48,028)			(48,028)
Inventories	4,164								4,164			5,138
Other assets, net of amortization	72,241								72,241			59,204
Liabilities and equity
Other liabilities	26,271								26,271			19,864
Partners’ capital, common units	$ 2,106								$ 2,106			$ (3,550)

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregated Revenue) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Total revenues	$ 2,912,770
Fee-based revenues | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	660,747
Product Sales | Transferred at point in time
Disaggregation of Revenue [Line Items]
Total revenues	2,149,223
Refinery Services | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	102,800
Onshore facilities and transportation
Disaggregation of Revenue [Line Items]
Total revenues	1,233,855
Onshore facilities and transportation | Fee-based revenues | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	156,266
Onshore facilities and transportation | Product Sales | Transferred at point in time
Disaggregation of Revenue [Line Items]
Total revenues	1,077,589
Onshore facilities and transportation | Refinery Services | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	0
Sodium minerals and sulfur services
Disaggregation of Revenue [Line Items]
Total revenues	1,174,434
Sodium minerals and sulfur services | Fee-based revenues | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	0
Sodium minerals and sulfur services | Product Sales | Transferred at point in time
Disaggregation of Revenue [Line Items]
Total revenues	1,071,634
Sodium minerals and sulfur services | Refinery Services | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	102,800
Offshore pipeline transportation services
Disaggregation of Revenue [Line Items]
Total revenues	284,544
Offshore pipeline transportation services | Fee-based revenues | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	284,544
Offshore pipeline transportation services | Product Sales | Transferred at point in time
Disaggregation of Revenue [Line Items]
Total revenues	0
Offshore pipeline transportation services | Refinery Services | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	0
Marine transportation
Disaggregation of Revenue [Line Items]
Total revenues	219,937
Marine transportation | Fee-based revenues | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	219,937
Marine transportation | Product Sales | Transferred at point in time
Disaggregation of Revenue [Line Items]
Total revenues	0
Marine transportation | Refinery Services | Transferred over time
Disaggregation of Revenue [Line Items]
Total revenues	$ 0

Revenue Recognition (Contract A

Revenue Recognition (Contract Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract Liabilities, Current	$ 72,241	$ 59,204	$ 0
Contract Liabilities, Non-Current		$ 19,864
Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract Liabilities, Current	72,241
Contract Liabilities, Non-Current	$ 26,271

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)
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	$ 0
Expected duration of performance obligations	1 year

Revenue Recognition (Revenue Ex

Revenue Recognition (Revenue Expected to be Recognized in Future Periods) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Offshore pipeline transportation services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 74,200
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	27,010
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	65,436
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	51,256
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	20,128
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	57,090
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	34,562
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	0
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	20,139
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	22,828
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	0
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, 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	12,076
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	0
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, 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	123,371
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	0
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, 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	318,293
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	47,138
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	$ 146,948

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details) - USD ($)	Sep. 01, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 14, 2017
Business Acquisition [Line Items]
Payments to acquire business		$ 0	$ 1,325,759,000	$ 25,394,000
Proceeds from issuance of Class A convertible preferred units, net		0	726,419,000	$ 0
Class A Convertible Preferred Stock Units
Business Acquisition [Line Items]
Private placement of convertible preferred units	$ 750,000,000
Class A Convertible Preferred Stock 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 Stock Units | Private Placement
Business Acquisition [Line Items]
Private placement of convertible preferred units	$ 750,000,000
Proceeds from issuance of Class A convertible preferred units, net	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, 2018	Dec. 31, 2017	Dec. 31, 2016
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per unit)	$ (0.62)	$ 0.50	$ 1
Alkali Business
Pro forma consolidated financial operating results:
Revenues		$ 2,549,438	$ 2,498,293
Net Income Attributable to Genesis Energy, L.P.		108,392	156,700
Net Income Available to Common Unitholders		$ 42,768	$ 91,076
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per unit)		$ 0.50	$ 1
Pro forma net income per common unit, basic and diluted (in dollars per unit)		$ 0.35	$ 0.80

Receivables (Schedule of Trade

Receivables (Schedule of Trade Accounts Receivables Net) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts Receivable, Net, Current [Abstract]
Accounts receivable - trade	$ 330,855		$ 503,917
Allowance for doubtful accounts	(7,393)		(8,468)	$ (6,505)	$ (1,446)
Accounts receivable - trade, net	$ 323,462	$ 447,421	$ 495,449

Receivables (Schedule of Allowa

Receivables (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance at beginning of period	$ 8,468	$ 6,505	$ 1,446
Charged to costs and expenses, net of recoveries	31	2,001	6,463
Amounts written off	(1,106)	(38)	(1,404)
Balance at end of period	$ 7,393	$ 8,468	$ 6,505

Inventories (Details)

Inventories (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
Inventory Disclosure [Abstract]
Petroleum products	$ 12,203,000	$ 8,731,000
Crude oil	8,379,000	29,873,000
Caustic soda	10,372,000	5,755,000
NaHS	12,400,000	8,277,000
Raw materials - Alkali Operations	5,952,000	4,550,000
Work-in-process - Alkali Operations	2,322,000	7,355,000
Finished goods, net - Alkali Operations	11,402,000	14,075,000
Materials and supplies, net - Alkali Operations	10,490,000	10,030,000
Other	11,000	7,000
Total	73,531,000	88,653,000	$ 93,791,000
Inventory write-down	$ 1,000,000	$ 0

Fixed Assets and Asset Retire_3

Fixed Assets and Asset Retirement Obligations (Schedule of Fixed Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 5,440,858	$ 5,601,015
Less: Accumulated depreciation	(1,023,825)	(734,986)
Net fixed assets	4,417,033	4,866,029
Crude oil pipelines and natural gas pipelines and related assets
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	2,918,285	3,028,657
Onshore facilities, machinery, and equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	639,023	692,364
Onshore facilities, machinery, and equipment | Alkali Business
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	533,924	497,601
Transportation equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	20,102	21,483
Marine vessels
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	951,597	918,953
Land, buildings and improvements
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	222,242	223,186
Office equipment, furniture and fixtures
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	20,505	18,112
Construction in progress
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	94,025	151,768
Other
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 41,155	$ 48,891

Fixed Assets and Asset Retire_4

Fixed Assets and Asset Retirement Obligations (Schedule of Mineral Leaseholds) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Mineral leaseholds	$ 566,019	$ 566,019
Less: Accumulated depletion	(5,538)	(1,513)
Mineral leaseholds, net	$ 560,481	$ 564,506

Fixed Assets and Asset Retire_5

Fixed Assets and Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Thousands	Oct. 11, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations Details [Line Items]
Depreciation expense		$ 286,000	$ 226,000	$ 194,000
Depletion expense		4,000	1,500
Impairment expense		126,282	0	0
Asset retirement obligation		239,865	198,187	$ 213,726
Current Liabilities - Accrued Liabilities
Asset Retirement Obligations Details [Line Items]
Asset retirement obligation		67,500	20,900
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
Non-Core Natural Gas Gathering and Platform Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | MEXICO
Asset Retirement Obligations Details [Line Items]
Gain on sale of assets			$ 40,300
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, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 198,187	$ 213,726
Accretion expense	10,509	11,008
Revisions in timing and estimated costs of AROs	44,319	7,146
Acquisitions		131
Divestitures		(7,649)
Settlements	(13,150)	(26,415)
Other		240
Asset retirement obligations, ending balance	$ 239,865	$ 198,187

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, 2018USD ($)
Forecast of Future Accretion Expense [Abstract]
2019	$ 9,928
2020	10,997
2021	9,313
2022	9,892
2023	$ 10,586

Equity Investees (Narrative) (D

Equity Investees (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Apr. 01, 2016	Mar. 31, 2016
Schedule of Equity Method Investments [Line Items]
Unamortized excess cost amount	$ 366.4	$ 382.4
Enterprise Offshore Acquisition | Deepwater Gateway LLC
Schedule of Equity Method Investments [Line Items]
Equity interest step up acquired percentage			100.00%	50.00%
Transaction costs related to business acquisition				$ 26

Net Investment in Direct Fina_3

Net Investment in Direct Financing Leases (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Leases [Abstract]
Fixed lease payments per year	$ 20.7
Fixed lease interest rate per year	10.25%
Minimum lease payments to be received in 2019	$ 20.7
Minimum lease payments to be received in 2020	20.7
Minimum lease payments to be received in 2021	20.7
Minimum lease payments to be received in 2022	20.7
Minimum lease payments to be received in 2023	$ 20.7

Equity Investees (Consolidated

Equity Investees (Consolidated Financial Statements Related to Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Genesis’ share of operating earnings	$ 59,255	$ 66,814	$ 63,805
Amortization of differences attributable to Genesis' carrying value of equity investments	(15,629)	(15,768)	(15,861)
Net equity in earnings	43,626	51,046	47,944
Distributions received	$ 71,714	$ 82,898	$ 87,220

Net Investment in Direct Fina_4

Net Investment in Direct Financing Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Leases [Abstract]
Total minimum lease payments to be received	$ 195,280	$ 215,884
Unamortized initial direct costs	801	950
Less unearned income	(70,735)	(83,918)
Net investment in direct financing leases	125,346	132,916
Less current portion (included in other current assets)	(8,421)	(7,633)
Long-term portion of net investment in direct financing leases	$ 116,925	$ 125,283

Equity Investees (Schedule of B

Equity Investees (Schedule of Balance Sheet Information for Equity Investees) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets
Current assets	$ 34,005	$ 34,381
Fixed assets, net	346,864	362,214
Other assets	15,469	14,927
Total assets	396,338	411,522
Liabilities and equity
Current liabilities	18,897	23,289
Other liabilities	250,742	249,610
Equity	126,699	138,623
Total liabilities and equity	$ 396,338	$ 411,522

Equity Investees (Schedule of O

Equity Investees (Schedule of Operations for Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
INCOME STATEMENT DATA:
Revenues	$ 180,056	$ 191,078	$ 193,038
Operating Income	129,160	139,604	122,836
Net Income	$ 115,669	$ 134,479	$ 118,175

Intangible Assets, Goodwill a_3

Intangible Assets, Goodwill and Other Assets (Schedule of Intangible Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 398,870	$ 396,823
Accumulated Amortization	236,268	214,417
Carrying Value	$ 162,602	182,406
Other
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 30,947	28,900
Accumulated Amortization	16,519	13,483
Carrying Value	14,428	15,417
Sodium minerals and sulfur services
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	134,132	134,132
Accumulated Amortization	133,688	129,110
Carrying Value	$ 444	5,022
Sodium minerals and sulfur services | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 94,654	94,654
Accumulated Amortization	94,654	92,493
Carrying Value	$ 0	2,161
Sodium minerals and sulfur services | Licensing agreements
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	6 years
Gross Carrying Amount	$ 38,678	38,678
Accumulated Amortization	38,678	36,528
Carrying Value	$ 0	2,150
Sodium minerals and sulfur services | Non-compete agreement
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	3 years
Gross Carrying Amount	$ 800	800
Accumulated Amortization	356	89
Carrying Value	444	711
Onshore facilities and transportation
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	48,690	48,690
Accumulated Amortization	40,530	40,015
Carrying Value	$ 8,160	8,675
Onshore facilities and transportation | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 35,430	35,430
Accumulated Amortization	35,123	35,082
Carrying Value	$ 307	348
Onshore facilities and transportation | Intangibles associated with lease
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	15 years
Gross Carrying Amount	$ 13,260	13,260
Accumulated Amortization	5,407	4,933
Carrying Value	$ 7,853	8,327
Marine transportation
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 27,000	27,000
Accumulated Amortization	17,100	11,700
Carrying Value	$ 9,900	15,300
Offshore pipeline transportation services
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	19 years
Gross Carrying Amount	$ 158,101	158,101
Accumulated Amortization	28,431	20,109
Carrying Value	$ 129,670	$ 137,992

Intangible Assets, Goodwill a_4

Intangible Assets, Goodwill and Other Assets (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Intangible Assets, Goodwill And Other Assets [Line Items]
Amortization of expense of intangible assets	$ 21,800	$ 23,600	$ 24,300
Goodwill	301,959	325,046
Amortization of CO2 assets	1,300	1,300	$ 3,900
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, 2018USD ($)
Finite-Lived Intangible Assets [Line Items]
2019	$ 17,654
2020	16,642
2021	10,843
2022	10,683
2023	10,397
Other
Finite-Lived Intangible Assets [Line Items]
2019	3,153
2020	3,132
2021	2,011
2022	1,853
2023	1,568
Sodium minerals and sulfur services | Non-compete agreement
Finite-Lived Intangible Assets [Line Items]
2019	267
2020	177
2021	0
2022	0
2023	0
Onshore facilities and transportation | Customer relationships
Finite-Lived Intangible Assets [Line Items]
2019	39
2020	38
2021	37
2022	35
2023	34
Onshore facilities and transportation | Intangibles associated with lease
Finite-Lived Intangible Assets [Line Items]
2019	474
2020	474
2021	474
2022	474
2023	474
Marine transportation
Finite-Lived Intangible Assets [Line Items]
2019	5,400
2020	4,500
2021	0
2022	0
2023	0
Offshore pipeline transportation services
Finite-Lived Intangible Assets [Line Items]
2019	8,321
2020	8,321
2021	8,321
2022	8,321
2023	$ 8,321

Intangible Assets, Goodwill a_6

Intangible Assets, Goodwill and Other Assets (Schedule of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
CO2 volumetric production payments, net of amortization	$ 890		$ 2,175
Deferred marine charges, net	28,175		30,246
Contract Liabilities	72,241	$ 59,204	0
Other deferred costs and deposits	20,401		24,207
Other assets, net of amortization	$ 121,707	$ 115,832	$ 56,628

Debt (Schedule of Obligations U

Debt (Schedule of Obligations Under Debt Arrangements) (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 11, 2017	May 21, 2015	May 15, 2014	Feb. 08, 2013
Debt Instrument [Line Items]
Senior secured credit facility	$ 970,100,000	$ 1,099,200,000
Unamortized discount an debt issuance costs	37,637,000	46,252,000
Senior unsecured notes, net of debt issuance costs	2,462,363,000	2,598,918,000
Long-term debt, principal	3,470,100,000	3,744,370,000
Total long-term debt, net value	3,432,463,000	3,698,118,000
5.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	0	145,170,000				$ 350,000,000
Unamortized discount an debt issuance costs	0	1,303,000
Senior unsecured notes, net of debt issuance costs	0	143,867,000
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	12,763,000	16,077,000
Senior unsecured notes, net of debt issuance costs	737,237,000	733,923,000
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	4,624,000	5,691,000
Senior unsecured notes, net of debt issuance costs	395,376,000	394,309,000
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	4,820,000	5,717,000
Senior unsecured notes, net of debt issuance costs	345,180,000	344,283,000
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	8,241,000	9,462,000
Senior unsecured notes, net of debt issuance costs	541,759,000	540,538,000
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	7,189,000	8,002,000
Senior unsecured notes, net of debt issuance costs	442,811,000	441,998,000
Senior secured credit facility
Debt Instrument [Line Items]
Unamortized discount an debt issuance costs	10,800,000	14,100,000
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, 2018USD ($)
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	$ 970,100,000
Total amount available for borrowings, remaining borrowing capacity	728,700,000
Senior secured credit facility | Petroleum Products
Debt Instrument [Line Items]
Senior secured credit facility, amount outstanding	$ 17,800,000
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	2.75%
Letters of credit, outstanding amount	$ 1,200,000
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	2.75%
Eurodollar Rate | Maximum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.50%
Letter of credit, fee percentage	3.00%
Eurodollar Rate | Minimum
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	3.00%
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	1.75%

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, 2018	Dec. 31, 2017	Dec. 31, 2016	May 15, 2014	Feb. 08, 2013
Debt Instrument [Line Items]
Redemption of senior unsecured debt							$ 145,170,000	$ 204,830,000	$ 0
Loss on extinguishment of debt	$ 3,300,000						3,339,000	6,242,000	0
Proceeds from issuance of unsecured debt							0	1,000,000,000	$ 0
Debt percentage of principal amount redeemed	101.438%
2021 Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal							0	145,170,000			$ 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
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, 2018
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	Jul. 27, 2016	Dec. 31, 2018	Dec. 31, 2017
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	$ 37.90
Net proceeds received from sale of units, net of underwriter discounts	$ 140,513	$ 298,452
Class A
Partners Capital And Distributions [Line Items]
Common units issued (in units)	4,600,000	8,000,000
Price per share of common units issued (in dollars per unit)	$ 30.65	$ 37.90
Additional common units to purchase (in units)	600,000
Net proceeds received from sale of units, net of underwriter discounts	$ 140,500	$ 298,500
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

Partners' Capital, Mezzanine _4

Partners' Capital, Mezzanine Equity and Distributions (Distributions Paid) (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 14, 2019	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017
Distribution Made to Limited Partner [Line Items]
Date Paid	Feb. 14, 2019						Aug. 14, 2017	May 15, 2017	Feb. 14, 2017
Per Unit Amount (in dollars per unit)	$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5100	$ 0.5000	$ 0.7225	$ 0.7200	$ 0.7100	$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5000	$ 0.7225	$ 0.7200	$ 0.7100
Total Amount	$ 67,419	$ 66,193	$ 64,967	$ 63,741	$ 62,515	$ 61,290	$ 88,563	$ 88,257	$ 83,765
Date Issued		Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017

Partners' Capital, Mezzanine _5

Partners' Capital, Mezzanine Equity and Distributions (New Common Units Issued to the Public for Cash) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 24, 2017	Jul. 27, 2016
Equity [Abstract]
Units (in units)	4,600	8,000
Gross Unit Price (in dollars per unit)	$ 30.65	$ 37.90
Issuance Value	$ 140,990	$ 303,200
Costs	(477)	(4,748)
Net Proceeds	$ 140,513	$ 298,452

Partners' Capital, Mezzanine _6

Partners' Capital, Mezzanine Equity and Distributions (Class A Convertible Preferred Units Narrative) (Details) $ / shares in Units, $ in Thousands	Sep. 01, 2024USD ($)directorshares	Sep. 01, 2022	Mar. 01, 2019quarter	Nov. 14, 2018USD ($)shares	Aug. 14, 2018USD ($)shares	May 15, 2018USD ($)shares	Feb. 14, 2018USD ($)shares	Nov. 14, 2017USD ($)shares	Sep. 01, 2017USD ($)buyer$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Sep. 01, 2019USD ($)
Temporary Equity [Line Items]
Class A convertible preferred units issued (in units) | shares										24,438,022	24,438,022	22,411,728
Accumulated distributions to preferred unitholders										$ 69,800	$ 69,800
Class A Convertible Preferred Stock Units
Temporary Equity [Line Items]
Private placement of convertible preferred units									$ 750,000
Number of shares authorized to be converted (in units) | shares									7,416,498
Consecutive period for shares to be converted									12 months
Minimum number of shares outstanding authorized to be converted (in units) | shares									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
Distribution paid-in-kind (in units) | shares				523,132	511,934	500,976	490,252	162,234		534,576	2,026,294	162,234
Distributions paid-in-kind				$ 17,635	$ 17,257	$ 16,888	$ 16,526	$ 5,469			$ 68,306	$ 5,469
Accumulated distributions to preferred unitholders										$ 69,800	$ 69,800
Class A Convertible Preferred Stock Units | In Arrears At Annual Rate
Temporary Equity [Line Items]
Dividend rate percentage									8.75%
Dividend amount (in dollars per unit) | $ / shares									$ 2.9496	$ 2.9496
Class A Convertible Preferred Stock Units | Quarterly Rate
Temporary Equity [Line Items]
Dividend rate percentage									2.1875%
Dividend amount (in dollars per unit) | $ / shares									$ 0.7374	$ 0.7374
Class A Convertible Preferred Stock Units | 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) | shares	11,124,747
Number of directors that initial purchasers have right to appoint | director	2
Class A Convertible Preferred Stock Units | Minimum
Temporary Equity [Line Items]
Redemption premium percentage									115.00%
Class A Convertible Preferred Stock Units | Maximum
Temporary Equity [Line Items]
Redemption premium percentage									101.00%
Class A Convertible Preferred Stock Units | LIBOR | Scenario, Forecast
Temporary Equity [Line Items]
Basis spread		7.50
Private Placement | Class A Convertible Preferred Stock Units
Temporary Equity [Line Items]
Private placement of convertible preferred units									$ 750,000
Class A convertible preferred units issued (in units) | shares									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 (Initial Measurement of Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	Sep. 01, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Temporary Equity [Line Items]
Transaction price, net		$ 697,151	$ 761,466
Class A Convertible Preferred Stock 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	$ 761,466	$ 0

Partners' Capital, Mezzanine _8

Partners' Capital, Mezzanine Equity and Distributions (Paid in Kind Distributions Paid) (Details) - USD ($) $ in Thousands	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Distribution Made to Limited Partner [Line Items]
Date Issued	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017
Class A Convertible Preferred Stock Units
Distribution Made to Limited Partner [Line Items]
Number of Units (in units)	523,132	511,934	500,976	490,252	162,234	534,576	2,026,294	162,234
Total Amount	$ 17,635	$ 17,257	$ 16,888	$ 16,526	$ 5,469		$ 68,306	$ 5,469

Partners' Capital, Mezzanine _9

Partners' Capital, Mezzanine Equity and Distributions (Change in Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Sep. 01, 2017	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Units
Beginning Balance (in units)								22,411,728
Ending Balance (in units)							24,438,022	24,438,022	22,411,728
Amount
Beginning Balance								$ 697,151
Ending Balance							$ 761,466	$ 761,466	$ 697,151
Class A Convertible Preferred Stock Units
Units
Beginning Balance (in units)								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)	523,132	511,934	500,976	490,252	162,234		534,576	2,026,294	162,234
Allocation of Distributions paid-kind to Preferred Distribution Rate Reset Election (in units)								0	0
Ending Balance (in units)							24,438,022	24,438,022	22,411,728
Amount
Beginning Balance								$ 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	$ 17,635	$ 17,257	$ 16,888	$ 16,526	$ 5,469			68,306	5,469
Allocation of Distribution paid-kind to Preferred Distribution Rate Reset Election								(3,991)	(287)
Ending Balance						$ 726,419	$ 761,466	$ 761,466	$ 697,151

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Genesis Energy L.P.	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ (6,075)	$ 82,647	$ 113,249
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(69,801)	(21,995)	0
Net Income (Loss) Available to Common Unitholders									$ (75,876)	$ 60,652	$ 113,249
Weighted Average Outstanding Units (in units)									122,579,000	121,546,000	113,433,000
Basic and Diluted (in dollars per unit)									$ (0.62)	$ 0.50	$ 1
Class A Convertible Preferred Stock Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share (in units)									24,438,022

Business Segment Information (S

Business Segment Information (Schedule of Revenues by Segment) (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jul. 24, 2015
Segment Reporting [Abstract]
Number of operating segments | segment									4
Segment Reporting Information [Line Items]
Total Segment Margin									$ 712,758	$ 594,543	$ 569,571
Total revenues	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 720,049	$ 486,114	$ 406,723	$ 415,491	2,912,770	2,028,377	1,712,493
Enterprise Offshore Acquisition | Deepwater Gateway LLC
Segment Reporting Information [Line Items]
Equity investment, ownership percentage												50.00%
Offshore pipeline transportation services
Segment Reporting Information [Line Items]
Total revenues									284,544	318,239	334,679
Offshore pipeline transportation services | Deepwater Gateway LLC
Segment Reporting Information [Line Items]
Capital Expenditures											35,100
Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Total revenues									1,174,434	462,622	171,503
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									1,233,855	1,042,229	993,290
Marine transportation
Segment Reporting Information [Line Items]
Total revenues									219,937	205,287	213,021
Operating Segments
Segment Reporting Information [Line Items]
Total Segment Margin									712,758	594,543	569,571
Capital Expenditures									161,393	1,580,821	443,993
External customers									2,912,770	2,028,377	1,712,493
Operating Segments | Offshore pipeline transportation services
Segment Reporting Information [Line Items]
Total Segment Margin									285,014	317,540	336,620
Capital Expenditures									4,703	8,815	46,277
External customers									284,544	319,455	332,514
Operating Segments | Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Total Segment Margin									260,488	130,333	79,508
Capital Expenditures									74,712	1,354,469	2,274
External customers									1,181,578	470,789	180,665
Operating Segments | Onshore facilities and transportation
Segment Reporting Information [Line Items]
Total Segment Margin									119,918	96,376	83,364
Capital Expenditures									51,110	149,123	316,638
External customers									1,240,382	1,044,083	993,103
Operating Segments | Marine transportation
Segment Reporting Information [Line Items]
Total Segment Margin									47,338	50,294	70,079
Capital Expenditures									30,868	68,414	78,804
External customers									206,266	194,050	206,211
Intersegment
Segment Reporting Information [Line Items]
Intersegment									0	0	0
Intersegment | Offshore pipeline transportation services
Segment Reporting Information [Line Items]
Intersegment									0	(1,216)	2,165
Intersegment | Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
Intersegment									(7,144)	(8,167)	(9,162)
Intersegment | Onshore facilities and transportation
Segment Reporting Information [Line Items]
Intersegment									(6,527)	(1,854)	187
Intersegment | Marine transportation
Segment Reporting Information [Line Items]
Intersegment									$ 13,671	$ 11,237	$ 6,810

Business Segment Information _2

Business Segment Information (Schedule of Total Assets by Reportable Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 6,479,071	$ 7,137,481	$ 5,702,592
Other assets
Segment Reporting Information [Line Items]
TOTAL ASSETS	43,060	49,737	43,089
Offshore pipeline transportation services
Segment Reporting Information [Line Items]
TOTAL ASSETS	2,359,013	2,486,803	2,575,335
Sodium minerals and sulfur services
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,844,845	1,848,188	395,043
Onshore facilities and transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,431,910	1,927,976	1,875,403
Marine transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 800,243	$ 824,777	$ 813,722

Business Segment Information (R

Business Segment Information (Reconciliation of Segment Margin to Net Income) (Details) - USD ($) $ in Thousands	Feb. 15, 2018	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Total Segment Margin										$ 712,758	$ 594,543	$ 569,571
Corporate general and administrative expenses										(64,683)	(60,029)	(40,905)
Depreciation, depletion, amortization and accretion										(317,186)	(262,021)	(230,563)
Interest expense										(229,191)	(176,762)	(139,947)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income										(28,088)	(31,852)	(39,276)
Non-cash items not included in Segment Margin										9,698	(14,305)	(3,221)
Cash payments from direct financing leases in excess of earnings										(7,633)	(6,921)	(6,277)
Loss on debt extinguishment	$ (3,300)									(3,339)	(6,242)	0
Differences in timing of cash receipts for certain contractual arrangements										6,629	17,540	13,253
Gain on sales of assets										42,264	40,311	0
Other, net										0	(2,985)	(6,044)
Non-cash provision for leased items no longer in use										476	(12,589)	0
Income tax benefit (expense)										(1,498)	3,959	(3,342)
Impairment expense										(126,282)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.		$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ (6,075)	$ 82,647	$ 113,249

Transactions with Related Par_3

Transactions with Related Parties (Schedule of Transactions With Related Parties) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018
Sandhill Group Llc
Related Party Transaction [Line Items]
Related party transaction, revenues		$ 1,233	$ 2,820	$ 3,097
Equity investment, ownership percentage					50.00%
Poseidon Oil Pipeline Company
Related Party Transaction [Line Items]
Related party transaction, revenues		12,557	12,357	10,844
Related party transaction, expenses		$ 994	986	1,007
Equity investment, ownership percentage		64.00%
ANSAC
Related Party Transaction [Line Items]
Related party transaction, revenues	$ 124,500	$ 373,606	124,536	0
Related party transaction, expenses	$ 2,200	5,284	2,242	0
CEO
Related Party Transaction [Line Items]
Related party transaction, expenses		$ 660	$ 660	$ 660

Transactions with Related Par_4

Transactions with Related Parties (Narrative) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Poseidon Oil Pipeline Company
Related Party Transaction [Line Items]
Net sales from related party		$ 12,557	$ 12,357	$ 10,844
Due from related parties	$ 2,200	2,400	2,200
Costs charged by related party, included in operating costs		994	986	1,007
Poseidon Oil Pipeline Company | Management Service
Related Party Transaction [Line Items]
Net sales from related party		8,600	8,400	7,900
ANSAC
Related Party Transaction [Line Items]
Net sales from related party	124,500	373,606	124,536	0
Due from related parties	74,490	60,594	74,490
Costs charged by related party, included in operating costs	$ 2,200	$ 5,284	$ 2,242	$ 0

Transactions with Related Par_5

Transactions with Related Parties (Schedule of Receivables From and Payables To Related Parties) (Details) - ANSAC - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivables	$ 60,594	$ 74,490
Payables	$ 815	$ 1,223

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, 2018	Dec. 31, 2017	Dec. 31, 2016
(Increase) decrease in:
Accounts receivable	$ 130,573	$ (140,948)	$ (9,859)
Inventories	20,963	49,055	(54,361)
Deferred charges	(5,826)	(3,622)	(3,902)
Other current assets	9,337	(410)	3,059
Increase (decrease) in:
Accounts payable	(130,991)	97,569	(17,426)
Accrued liabilities	(26,208)	8,512	(8,161)
Net changes in components of operating assets and liabilities	$ (2,152)	$ 10,156	$ (90,650)

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Payments of interest and commitment fees	$ 228.3	$ 168.3	$ 157.4
Capitalized interest	3.4	15	26.6
Cash paid for income taxes	0.2	1	1.3
Incurred liabilities for fixed and intangible asset additions	$ 9.4	$ 39.7	$ 33.7

Equity-Based Compensation Pla_3

Equity-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 1,971	$ (4,577)	$ 8,580
Service-Based Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in units)	28,484
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 22.12
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)	28,484	297,214	339,584
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 22.12	$ 32.37	$ 30.71
Unrecognized compensation cost	$ 600
Weighted average period of recognition, years	9 months 18 days
Compensation expense	$ 2,100	$ 3,400
Liability for compensation awards	$ 3,300	$ 3,200
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%	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%	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%	33.33%
2010 Plan | Performance-Based Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage		150.00%	150.00%
2010 Plan | Performance-Based Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage		0.00%	50.00%
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%	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%	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%	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, 2018USD ($)$ / sharesshares
Service-Based Awards
Number of Phantom Units
Unvested at December 31, 2017 (in units) | shares	239,837
Granted (in units) | shares	28,484
Forfeited (in units) | shares	(17,073)
Settled (in units) | shares	(55,309)
Unvested at December 31, 2018 (in units) | shares	195,939
Average Grant Date Fair Value
Unvested at December 31, 2017 (in dollars unit) | $ / shares	$ 34.81
Granted (in dollars per unit) | $ / shares	22.12
Forfeited (in dollars per unit) | $ / shares	31.46
Settled (in dollars per unit) | $ / shares	44.92
Unvested at December 31, 2018 (in dollars per unit) | $ / shares	$ 30.40
Total Value (in thousands)
Unvested at December 31, 2017 | $	$ 8,349
Granted | $	630
Forfeited | $	(537)
Settled | $	(2,484)
Unvested at December 31, 2018 | $	$ 5,958
Performance-Based Awards
Number of Phantom Units
Unvested at December 31, 2017 (in units) | shares	582,375
Granted (in units) | shares	0
Forfeited (in units) | shares	(67,266)
Settled (in units) | shares	(137,103)
Unvested at December 31, 2018 (in units) | shares	378,006
Average Grant Date Fair Value
Unvested at December 31, 2017 (in dollars unit) | $ / shares	$ 34.73
Granted (in dollars per unit) | $ / shares	0
Forfeited (in dollars per unit) | $ / shares	33.49
Settled (in dollars per unit) | $ / shares	45.40
Unvested at December 31, 2018 (in dollars per unit) | $ / shares	$ 31.09
Total Value (in thousands)
Unvested at December 31, 2017 | $	$ 20,228
Granted | $	0
Forfeited | $	(2,253)
Settled | $	(6,224)
Unvested at December 31, 2018 | $	$ 11,751

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ 1,971	$ (4,577)	$ 8,580
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	140	(1,137)	1,688
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	183	(483)	1,089
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	112	(533)	547
Cost of goods and services sold | Offshore pipeline transportation services
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	297	(152)	681
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ 1,239	$ (2,272)	$ 4,575

Major Customers and Credit Ri_2

Major Customers and Credit Risk (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Customer Concentration Risk | Supply And Logistics Revenues | Shell Oil Company
Concentration Risk [Line Items]
Concentration risk, percentage	11.00%	13.00%	12.00%

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivatives Entered Into to Hedge Inventory or Fixed Price Purchase Commitments) (Details) bbl in Thousands	12 Months Ended
	Dec. 31, 2018bbl$ / bbl$ / units
Sell (Short) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	56
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	53.11
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	293
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	49.85
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	137
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	3.53
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Diesel
Derivative [Line Items]
Contract volumes (1,000 bbls)	2
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	1.89
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | RBOB Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	2
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	1.35
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Fuel Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	382
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	51.41
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	502
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	0.62
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Options | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	26
Weighted average premium received (in dollars per barrel) | $ / bbl	2.66
Buy (Long) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	0
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	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)	234
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	49.37
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	590
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	2.91
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Diesel
Derivative [Line Items]
Contract volumes (1,000 bbls)	2
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	1.85
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | RBOB Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	1
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	1.29
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Fuel Oil
Derivative [Line Items]
Contract volumes (1,000 bbls)	40
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	49.94
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Contract volumes (1,000 bbls)	0
Weighted average contract price per bbl (in dollars per barrel) | $ / units	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)	0
Weighted average premium received (in dollars per barrel) | $ / bbl	0

Derivatives (Fair Value of Deri

Derivatives (Fair Value of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Liability Derivatives:
Preferred Distribution Rate Reset Election	$ (40,800)
Embedded Derivative Financial Instruments | Other Long-Term Liabilities
Liability Derivatives:
Preferred Distribution Rate Reset Election	(40,840)	$ (45,209)
Not Designated As Hedging Instrument | Commodity Derivatives | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	3,431	505
Gross amount offset in the Consolidated Balance Sheets	(1,361)	(505)
Net amount of assets presented in the Consolidated Balance Sheets	2,070	0
Liability Derivatives:
Gross amount of recognized liabilities	(1,361)	(1,203)
Gross amount offset in the Consolidated Balance Sheets	1,361	1,203
Net amount of liabilities presented in the Consolidated Balance Sheets	0	0
Not Designated As Hedging Instrument | Swap | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	1,274	0
Not Designated As Hedging Instrument | Swap | Current Liabilities - Accrued Liabilities
Liability Derivatives:
Gross amount of recognized liabilities	(125)	0
Designated as Hedging Instrument | Commodity Derivatives | Current Assets - Other
Asset Derivatives:
Gross amount of recognized assets	469	54
Gross amount offset in the Consolidated Balance Sheets	(44)	(54)
Net amount of assets presented in the Consolidated Balance Sheets	425	0
Liability Derivatives:
Gross amount of recognized liabilities	(44)	(863)
Gross amount offset in the Consolidated Balance Sheets	44	338
Net amount of liabilities presented in the Consolidated Balance Sheets	$ 0	$ (525)

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 01, 2022	Mar. 01, 2019
Derivatives, Fair Value [Line Items]
Net broker receivables	$ 2.2	$ 1
Margin deposit assets	3.1	1.3
Increase (decrease) in variation margin deposits outstanding	(0.9)	$ (0.3)
Fair value of embedded derivative liability	$ 40.8
Convertible Preferred Units
Derivatives, Fair Value [Line Items]
Basis spread				2
Convertible Preferred Units | Scenario, Forecast
Derivatives, Fair Value [Line Items]
Reset rate			10.75%
Percentage below issue price			110.00%
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, 2018	Dec. 31, 2017	Dec. 31, 2016
Embedded Derivative Financial Instruments | Other Income (Expense)
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	$ 8,360	$ (10,472)	$ 0
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	(544)	5,116	(13,195)
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	3,370	3,802	(19,042)
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	3,914	(1,314)	(5,847)
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	$ 1,906	$ 0	$ 0

Fair-Value Measurements (Fair V

Fair-Value Measurements (Fair Value of Financial Assets Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Level 1 | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 3,900	$ 559
Liabilities	(1,405)	(2,066)
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	1,274	0
Liabilities	(125)	0
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	$ (40,840)	$ (45,209)

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, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	$ (45,209)	$ 0
Initial valuation of Preferred Distribution Rate Reset Election		(34,450)
Net (loss) gain for the period included in earnings	8,360	(10,472)
Allocation of Distribution Paid-in-kind	(3,991)	(287)
Ending Balance	$ (40,840)	$ (45,209)

Fair-Value Measurements (Narrat

Fair-Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Senior unsecured notes, net of debt issuance costs	$ 2,462,363	$ 2,598,918
Fair value of debt	$ 2,300,000	$ 2,700,000

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details)	Sep. 01, 2017
Alkali Business | 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, 2018	Dec. 31, 2017
Change in benefit obligation:
Benefit Obligation, beginning of year	$ 22,530	$ 0
Service Cost	5,153	1,749
Interest Cost	862	267
Actuarial (Gain) Loss	(3,816)	992
Benefits Paid	(218)	(56)
Acquisition of Alkali Business	0	19,578
Benefit Obligation, end of year	24,511	22,530
Change in plan assets:
Fair Value of Plan Assets, beginning of year	13,306	0
Actual Return (loss) on Plan Assets	(1,300)	647
Employer Contributions	3,928	2,250
Benefits Paid	(218)	(56)
Acquisition of Alkali Business	0	10,465
Fair Value of Plan assets, end of year	15,716	13,306
Funded Status at end of period	(8,795)	(9,224)
Amounts recognized in the Consolidated Balance Sheet:
Non-current assets	0	0
Current liabilities	0	0
Non-current Liabilities	(8,795)	(9,224)
Net Liability at end of year	(8,795)	(9,224)
Amounts recognized in accumulated other comprehensive income (loss):
Net actuarial (gain) loss	(939)	604
Amounts recognized in accumulated other comprehensive income ( loss:)	$ (939)	$ 604

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Contributions and Future Benefit Payments) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Employer Contributions
Expected 2019 Contributions by Employer	$ 3,550
Future Expected Benefit Payments
2019	587
2020	816
2021	962
2022	1,109
2023	1,265
2024-2028	$ 8,465

Employee Benefit Plans (Compone

Employee Benefit Plans (Components of Net Periodic Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Retirement Benefits [Abstract]
Service Cost	$ 5,153	$ 1,749
Interest Cost	862	267
Expected Return on Assets	(973)	(259)
Net Periodic Pension Costs	$ 5,042	$ 1,757

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value Assumptions) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount Rate	4.62%	3.90%
Expected Long-term Rate of Return	6.41%	6.28%

Employee Benefit Plans (Asset T

Employee Benefit Plans (Asset Target Allocation) (Details)	Dec. 31, 2018
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Actual %	51.00%
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
Defined Benefit Plan Disclosure [Line Items]
Actual %	41.00%
Fixed income securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target %	40.00%
Fixed income securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target %	50.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Actual %	8.00%
Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target %	0.00%
Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target %	10.00%

Employee Benefit Plans (Fair _2

Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 15,716	$ 13,306	$ 0
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	506	260
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	8,038	2,518
Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	7,172	10,528
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	15,716	13,306
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	506	260
Level 1 | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	8,038	2,518
Level 1 | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	7,172	10,528
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

Commitments and Contingencies_2

Commitments and Contingencies (Future Minimum Rental Payments Under All Non-Cancelable Operating Leases) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Property Subject to or Available for Operating Lease [Line Items]
2019	$ 46,042
2020	39,355
2021	30,674
2022	27,458
2023	27,629
2024 and thereafter	126,229
Total minimum lease obligations	297,387
Office Space
Property Subject to or Available for Operating Lease [Line Items]
2019	4,197
2020	4,119
2021	3,298
2022	2,692
2023	961
2024 and thereafter	3,735
Total minimum lease obligations	19,002
Transportation equipment
Property Subject to or Available for Operating Lease [Line Items]
2019	27,547
2020	24,642
2021	19,536
2022	18,113
2023	17,290
2024 and thereafter	45,390
Total minimum lease obligations	152,518
Terminals and Tanks
Property Subject to or Available for Operating Lease [Line Items]
2019	14,298
2020	10,594
2021	7,840
2022	6,653
2023	9,378
2024 and thereafter	77,104
Total minimum lease obligations	$ 125,867

Commitments and Contingencies_3

Commitments and Contingencies (Total Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Operating lease expense	$ 30,798	$ 36,933	$ 41,906

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Benefit relating to the U.S. federal corporate tax rate change	$ 0	$ 5,270	$ 0

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal	$ 0	$ 0	$ 0
State	810	100	1,200
Total current income tax expense	810	100	1,200
Deferred:
Federal	114	(5,530)	1,862
State	574	1,471	280
Total deferred income tax expense (benefit)	688	(4,059)	2,142
Income tax expense (benefit)	$ 1,498	$ (3,959)	$ 3,342

Income Taxes (Deferred Tax Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Net operating loss carryforwards	$ 11,491	$ 9,506
Total long-term deferred tax asset	11,491	9,506
Valuation allowances	(1,758)	(1,285)
Total deferred tax assets	9,733	8,221
Deferred tax liabilities:
Fixed assets	(2,893)	(3,896)
Intangible assets	(18,209)	(15,797)
Other	(1,207)	(441)
Total long-term liability	(22,309)	(20,134)
Total deferred tax liabilities	(22,309)	(20,134)
Total net deferred tax liability	$ (12,576)	$ (11,913)

Income Taxes (Federal Statutory

Income Taxes (Federal Statutory Income Tax Rate to Income Before Income Taxes) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income (loss) from operations before income taxes	$ (10,294,000)	$ 78,120,000	$ 114,424,000
Partnership income not subject to federal income tax	10,824,000	(77,704,000)	(109,111,000)
Income subject to federal income taxes	530,000	416,000	5,313,000
Tax expense at federal statutory rate	111,000	146,000	1,860,000
State income taxes, net of federal tax	1,285,000	1,396,000	949,000
Return to provision, federal and state	(128,000)	(163,000)	(198,000)
Other	230,000	(68,000)	731,000
Re-measurement of deferred taxes due to enacted tax rate change	0	(5,270,000)	0
Income tax expense (benefit)	$ 1,498,000	$ (3,959,000)	$ 3,342,000
Effective tax rate on income from operations before income taxes	(15.00%)	(5.00%)	3.00%
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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 14, 2019	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017
Quarterly Financial Data [Abstract]
Revenues from continuing operations	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 720,049	$ 486,114	$ 406,723	$ 415,491	$ 2,912,770	$ 2,028,377	$ 1,712,493
Operating income	4,119	46,148	60,900	59,081	63,407	43,100	61,447	52,597	170,248	220,551	206,427
Net income (loss)	(28,927)	(1,634)	10,871	7,898	15,401	6,160	33,580	26,938	(11,792)	82,079	111,082
Net loss attributable to noncontrolling interests	4,144	1,311	126	136	111	152	153	152	5,717	568	2,167
Net income (loss) attributable to Genesis Energy, L.P.	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ (6,075)	$ 82,647	$ 113,249
Basic and diluted net income (loss) per common unit:
Net income per common unit (in dollars per unit)	$ (0.35)	$ (0.15)	$ (0.05)	$ (0.07)	$ (0.01)	$ 0.01	$ 0.28	$ 0.23
Cash distributions per common unit (in dollars per unit)	$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5000	$ 0.7225	$ 0.7200	$ 0.7100	$ 0.5500	$ 0.5000		$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5100	$ 0.5000	$ 0.7225	$ 0.7200	$ 0.7100

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information (Narrative) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2018USD ($)
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, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents	$ 10,300		$ 9,041	$ 7,029	$ 10,895
Other current assets	432,979		626,992
Total current assets	443,279		636,033
Fixed assets, at cost	5,440,858		5,601,015
Less: Accumulated depreciation	(1,023,825)		(734,986)
Net fixed assets	4,417,033		4,866,029
Mineral Leaseholds, net of accumulated depletion	560,481		564,506
Goodwill	301,959		325,046
Other assets, net	401,234		364,317
Advances to affiliates	0		0
Equity investees	355,085		381,550
Investments in subsidiaries	0		0
TOTAL ASSETS	6,479,071		7,137,481	5,702,592
LIABILITIES AND CAPITAL
Current liabilities	332,834		456,264
Senior secured credit facility	970,100		1,099,200
Senior unsecured notes, net of debt issuance costs	2,462,363		2,598,918
Deferred tax liabilities	12,576		11,913
Advances from affiliates	0		0
Other liabilities	259,198	$ 276,435	256,571
Total liabilities	4,037,071		4,422,866
Mezzanine Capital:
Class A Convertible Preferred Units	761,466		697,151
Partners’ capital, common units	1,690,799	$ 2,022,597	2,026,147
Accumulated other comprehensive income (loss)	939		(604)
Noncontrolling interests	(11,204)		(8,079)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	6,479,071		7,137,481
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
ASSETS
Cash and cash equivalents	0		0	0	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	0		0
Advances to affiliates	0		0
Equity investees	0		0
Investments in subsidiaries	0		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
Partners’ capital, common units	0		0
Accumulated other comprehensive income (loss)	0		0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	0		0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
ASSETS
Cash and cash equivalents	6		6	6	6
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	10,776		14,083
Advances to affiliates	3,305,568		3,808,712
Equity investees	0		0
Investments in subsidiaries	2,648,510		2,689,861
TOTAL ASSETS	5,964,910		6,512,712
LIABILITIES AND CAPITAL
Current liabilities	39,342		46,086
Senior secured credit facility	970,100		1,099,200
Senior unsecured notes, net of debt issuance costs	2,462,363		2,598,918
Deferred tax liabilities	0		0
Advances from affiliates	0		0
Other liabilities	40,840		45,210
Total liabilities	3,512,645		3,789,414
Mezzanine Capital:
Class A Convertible Preferred Units	761,466		697,151
Partners’ capital, common units	1,690,799		2,026,147
Accumulated other comprehensive income (loss)	0		0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	5,964,910		6,512,712
Reportable Legal Entities | Guarantor Subsidiaries
ASSETS
Cash and cash equivalents	4,924		5,230	6,360	8,288
Other current assets	229,411		407,821
Total current assets	234,335		413,051
Fixed assets, at cost	4,602,164		4,832,639
Less: Accumulated depreciation	(926,830)		(692,193)
Net fixed assets	3,675,334		4,140,446
Mineral Leaseholds, net of accumulated depletion	0		0
Goodwill	301,959		325,046
Other assets, net	435,540		372,201
Advances to affiliates	0		0
Equity investees	355,085		381,550
Investments in subsidiaries	1,413,334		1,431,550
TOTAL ASSETS	6,415,587		7,063,844
LIABILITIES AND CAPITAL
Current liabilities	177,104		307,673
Senior secured credit facility	0		0
Senior unsecured notes, net of debt issuance costs	0		0
Deferred tax liabilities	12,576		11,913
Advances from affiliates	3,411,515		3,894,627
Other liabilities	174,249		166,705
Total liabilities	3,775,444		4,380,918
Mezzanine Capital:
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	2,640,143		2,682,926
Accumulated other comprehensive income (loss)	0		0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	6,415,587		7,063,844
Reportable Legal Entities | Non-Guarantor Subsidiaries
ASSETS
Cash and cash equivalents	5,370		3,805	663	2,601
Other current assets	203,683		219,177
Total current assets	209,053		222,982
Fixed assets, at cost	838,694		768,376
Less: Accumulated depreciation	(96,995)		(42,793)
Net fixed assets	741,699		725,583
Mineral Leaseholds, net of accumulated depletion	560,481		564,506
Goodwill	0		0
Other assets, net	122,538		132,470
Advances to affiliates	105,917		86,023
Equity investees	0		0
Investments in subsidiaries	0		0
TOTAL ASSETS	1,739,688		1,731,564
LIABILITIES AND CAPITAL
Current liabilities	116,498		102,761
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	211,590		198,946
Total liabilities	328,088		301,707
Mezzanine Capital:
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	1,421,865		1,438,540
Accumulated other comprehensive income (loss)	939		(604)
Noncontrolling interests	(11,204)		(8,079)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	1,739,688		1,731,564
Eliminations
ASSETS
Cash and cash equivalents	0		0	$ 0	$ 0
Other current assets	(165)		(56)
Total current assets	(165)		(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	(167,620)		(154,437)
Advances to affiliates	(3,411,485)		(3,894,735)
Equity investees	0		0
Investments in subsidiaries	(4,061,844)		(4,121,411)
TOTAL ASSETS	(7,641,114)		(8,170,639)
LIABILITIES AND CAPITAL
Current liabilities	(110)		(256)
Senior secured credit facility	0		0
Senior unsecured notes, net of debt issuance costs	0		0
Deferred tax liabilities	0		0
Advances from affiliates	(3,411,515)		(3,894,627)
Other liabilities	(167,481)		(154,290)
Total liabilities	(3,579,106)		(4,049,173)
Mezzanine Capital:
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	(4,062,008)		(4,121,466)
Accumulated other comprehensive income (loss)	0		0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$ (7,641,114)		$ (8,170,639)

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REVENUES:
Total revenues	$ 689,296	$ 745,278	$ 752,388	$ 725,808	$ 720,049	$ 486,114	$ 406,723	$ 415,491	$ 2,912,770	$ 2,028,377	$ 1,712,493
COSTS AND EXPENSES:
General and administrative									66,898	66,421	45,625
Depreciation, depletion and amortization									313,190	252,480	222,196
Gain on sale of assets									(42,264)	(40,311)	0
Impairment expense									126,282	0	0
Total costs and expenses									2,742,522	1,807,826	1,506,066
OPERATING INCOME	4,119	46,148	60,900	59,081	63,407	43,100	61,447	52,597	170,248	220,551	206,427
Equity in earnings of equity investees									43,626	51,046	47,944
Equity in earnings of subsidiaries									0	0	0
Interest expense									(229,191)	(176,762)	(139,947)
Other income (expense)									5,023	(16,715)	0
Income (loss) from operations before income taxes									(10,294)	78,120	114,424
Income tax benefit (expense)									(1,498)	3,959	(3,342)
NET INCOME (LOSS)	(28,927)	(1,634)	10,871	7,898	15,401	6,160	33,580	26,938	(11,792)	82,079	111,082
Net loss attributable to noncontrolling interests	4,144	1,311	126	136	111	152	153	152	5,717	568	2,167
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$ (24,783)	$ (323)	$ 10,997	$ 8,034	$ 15,512	$ 6,312	$ 33,733	$ 27,090	(6,075)	82,647	113,249
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(69,801)	(21,995)	0
Net Income (Loss) Available to Common Unitholders									(75,876)	60,652	113,249
Offshore pipeline transportation services
REVENUES:
Total revenues									284,544	318,239	334,679
COSTS AND EXPENSES:
Cost of products and services sold									66,668	72,065	79,624
Sodium minerals and sulfur services
REVENUES:
Total revenues									1,174,434	462,622	171,503
COSTS AND EXPENSES:
Cost of products and services sold									912,491	333,918	91,443
Marine transportation
REVENUES:
Total revenues									219,937	205,287	213,021
COSTS AND EXPENSES:
Cost of products and services sold									172,527	154,606	142,551
Onshore facilities and transportation
REVENUES:
Total revenues									1,233,855	1,042,229	993,290
COSTS AND EXPENSES:
Cost of products and services sold									1,126,730	968,647	924,627
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
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 attributable to noncontrolling interests									0	0	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 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) | 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 | 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									219,615	276,341	253,048
Interest expense									(230,713)	(176,979)	(139,799)
Other income (expense)									5,023	(16,715)
Income (loss) from operations before income taxes									(6,075)	82,647	113,249
Income tax benefit (expense)									0	0	0
NET INCOME (LOSS)									(6,075)	82,647	113,249
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									(6,075)	82,647	113,249
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(69,801)	(21,995)	0
Net Income (Loss) Available to Common Unitholders									(75,876)	60,652	113,249
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer) | Offshore pipeline transportation 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) | 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 | Guarantor Subsidiaries
REVENUES:
Total revenues									2,052,211	1,732,671	1,691,883
COSTS AND EXPENSES:
General and administrative									65,481	65,862	45,625
Depreciation, depletion and amortization									249,820	232,303	219,696
Gain on sale of assets									(42,264)	(40,311)
Impairment expense									100,093
Total costs and expenses									1,995,030	1,566,467	1,490,941
OPERATING INCOME									57,181	166,204	200,942
Equity in earnings of equity investees									43,626	51,046	47,944
Equity in earnings of subsidiaries									107,684	41,494	(6,744)
Interest expense									13,027	13,825	14,407
Other income (expense)									0	0
Income (loss) from operations before income taxes									221,518	272,569	256,549
Income tax benefit (expense)									(1,727)	3,928	(3,337)
NET INCOME (LOSS)									219,791	276,497	253,212
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									219,791	276,497	253,212
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									219,791	276,497	253,212
Reportable Legal Entities | Guarantor Subsidiaries | Offshore pipeline transportation services
REVENUES:
Total revenues									284,544	318,239	334,679
COSTS AND EXPENSES:
Cost of products and services sold									64,272	69,225	68,791
Reportable Legal Entities | Guarantor Subsidiaries | Sodium minerals and sulfur services
REVENUES:
Total revenues									333,495	185,852	171,389
COSTS AND EXPENSES:
Cost of products and services sold									259,573	117,224	90,711
Reportable Legal Entities | Guarantor Subsidiaries | Marine transportation
REVENUES:
Total revenues									219,937	205,287	213,021
COSTS AND EXPENSES:
Cost of products and services sold									172,527	154,606	142,551
Reportable Legal Entities | Guarantor Subsidiaries | Onshore facilities and transportation
REVENUES:
Total revenues									1,214,235	1,023,293	972,794
COSTS AND EXPENSES:
Cost of products and services sold									1,125,528	967,558	923,567
Reportable Legal Entities | Non-Guarantor Subsidiaries
REVENUES:
Total revenues									875,841	305,199	28,369
COSTS AND EXPENSES:
General and administrative									1,417	559	0
Depreciation, depletion and amortization									63,370	20,177	2,500
Gain on sale of assets									0	0
Impairment expense									26,189
Total costs and expenses									762,774	250,852	22,884
OPERATING INCOME									113,067	54,347	5,485
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									0	0	0
Interest expense									(11,505)	(13,608)	(14,555)
Other income (expense)									0	0
Income (loss) from operations before income taxes									101,562	40,739	(9,070)
Income tax benefit (expense)									229	31	(5)
NET INCOME (LOSS)									101,791	40,770	(9,075)
Net loss attributable to noncontrolling interests									5,717	568	2,167
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									107,508	41,338	(6,908)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									107,508	41,338	(6,908)
Reportable Legal Entities | Non-Guarantor Subsidiaries | Offshore pipeline transportation services
REVENUES:
Total revenues									0	0	0
COSTS AND EXPENSES:
Cost of products and services sold									2,396	2,840	10,833
Reportable Legal Entities | Non-Guarantor Subsidiaries | Sodium minerals and sulfur services
REVENUES:
Total revenues									856,221	286,263	7,873
COSTS AND EXPENSES:
Cost of products and services sold									668,200	226,187	8,491
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									19,620	18,936	20,496
COSTS AND EXPENSES:
Cost of products and services sold									1,202	1,089	1,060
Eliminations
REVENUES:
Total revenues									(15,282)	(9,493)	(7,759)
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									(15,282)	(9,493)	(7,759)
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									(327,299)	(317,835)	(246,304)
Interest expense									0	0	0
Other income (expense)									0	0
Income (loss) from operations before income taxes									(327,299)	(317,835)	(246,304)
Income tax benefit (expense)									0	0	0
NET INCOME (LOSS)									(327,299)	(317,835)	(246,304)
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.									(327,299)	(317,835)	(246,304)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income (Loss) Available to Common Unitholders									(327,299)	(317,835)	(246,304)
Eliminations | Offshore pipeline transportation services
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									(15,282)	(9,493)	(7,759)
COSTS AND EXPENSES:
Cost of products and services sold									(15,282)	(9,493)	(7,759)
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, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 390,039	$ 323,556	$ 282,752
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(195,367)	(250,593)	(463,100)
Cash distributions received from equity investees - return of investment	28,979	35,582	36,939
Investments in equity investees	(3,018)	(4,647)	0
Acquisitions	0	(1,325,759)	(25,394)
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	0	124	13,374
Proceeds from asset sales	310,099	85,722	3,609
Other, net	0	0	(151)
Net cash used in (provided by) investing activities	140,693	(1,459,571)	(434,723)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	980,700	1,458,700	1,115,800
Repayments on senior secured credit facility	(1,109,800)	(1,637,700)	(952,600)
Proceeds from issuance of senior unsecured notes	0	1,000,000	0
Proceeds from issuance of Class A convertible preferred units, net	0	726,419	0
Repayment of senior unsecured notes	(145,170)	(204,830)	0
Debt issuance costs	(242)	(25,913)	(1,578)
Intercompany transfers	0	0	0
Issuance of common units for cash, net	0	140,513	298,020
Distributions to partners/owners	(257,416)	(321,875)	(310,039)
Contributions from noncontrolling interests	2,592	2,770	236
Other, net	(137)	(57)	(1,734)
Net cash provided by (used in) financing activities	(529,473)	1,138,027	148,105
Net increase in cash and cash equivalents	1,259	2,012	(3,866)
Cash and cash equivalents at beginning of period	9,041	7,029	10,895
Cash and cash equivalents at end of period	10,300	9,041	7,029
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) 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	0
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs		0	0
Proceeds from asset sales	0	0	0
Other, net			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
Proceeds from issuance of Class A convertible preferred units, net		0
Repayment of senior unsecured notes	0	0
Debt issuance costs	0	0	0
Intercompany transfers	0	0	0
Issuance of common units for cash, net		0	0
Distributions to partners/owners	0	0	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	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(360,711)	(318,764)	(289,421)
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	140,513	298,020
Acquisitions		0	0
Intercompany transfers	(503,144)	2,482,781	31,436
Repayments on loan to non-guarantor subsidiary	(7,484)	(6,764)	(6,113)
Contributions in aid of construction costs		0	0
Proceeds from asset sales	0	0	0
Other, net			0
Net cash used in (provided by) investing activities	(510,628)	2,616,530	323,343
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
Proceeds from issuance of Class A convertible preferred units, net		0
Repayment of senior unsecured notes	0	0
Debt issuance costs	0	0	0
Intercompany transfers	503,144	(2,482,781)	(31,437)
Issuance of common units for cash, net		(140,513)	(298,020)
Distributions to partners/owners	381,316	339,375	310,039
Contributions from noncontrolling interests	0	0	0
Other, net	(13,121)	(13,847)	(14,504)
Net cash provided by (used in) financing activities	871,339	(2,297,766)	(33,922)
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Genesis Energy, L.P. (Parent and Co-Issuer) | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	28,784	162,980	179,853
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	(140,513)	(298,020)
Acquisitions		0	0
Intercompany transfers	503,144	(1,157,781)	(31,436)
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs		0	0
Proceeds from asset sales	0	0	0
Other, net			0
Net cash used in (provided by) investing activities	503,144	(1,298,294)	(329,456)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	980,700	1,458,700	1,115,800
Repayments on senior secured credit facility	(1,109,800)	(1,637,700)	(952,600)
Proceeds from issuance of senior unsecured notes		1,000,000
Proceeds from issuance of Class A convertible preferred units, net		726,419
Repayment of senior unsecured notes	(145,170)	(204,830)
Debt issuance costs	(242)	(25,913)	(1,578)
Intercompany transfers	0	0	0
Issuance of common units for cash, net		140,513	298,020
Distributions to partners/owners	(257,416)	(321,875)	(310,039)
Contributions from noncontrolling interests	0	0	0
Other, net	0	0	0
Net cash provided by (used in) financing activities	(531,928)	1,135,314	149,603
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	6	6	6
Cash and cash equivalents at end of period	6	6	6
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	514,096	448,873	382,734
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(114,887)	(236,151)	(463,100)
Cash distributions received from equity investees - return of investment	28,979	35,582	36,939
Investments in equity investees	(3,018)	(4,647)	0
Acquisitions		(759)	(25,394)
Intercompany transfers	0	(1,325,000)	0
Repayments on loan to non-guarantor subsidiary	7,484	6,764	6,113
Contributions in aid of construction costs		124	13,374
Proceeds from asset sales	310,099	85,722	3,609
Other, net			(151)
Net cash used in (provided by) investing activities	228,657	(1,438,365)	(428,610)
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
Proceeds from issuance of Class A convertible preferred units, net		0
Repayment of senior unsecured notes	0	0
Debt issuance costs	0	0	0
Intercompany transfers	(485,506)	1,169,781	57,701
Issuance of common units for cash, net		140,513	298,020
Distributions to partners/owners	(257,416)	(321,875)	(310,039)
Contributions from noncontrolling interests	0	0	0
Other, net	(137)	(57)	(1,734)
Net cash provided by (used in) financing activities	(743,059)	988,362	43,948
Net increase in cash and cash equivalents	(306)	(1,130)	(1,928)
Cash and cash equivalents at beginning of period	5,230	6,360	8,288
Cash and cash equivalents at end of period	4,924	5,230	6,360
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	207,870	30,467	9,586
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(80,480)	(14,442)	0
Cash distributions received from equity investees - return of investment	0	0	0
Investments in equity investees	0	0	0
Acquisitions		(1,325,000)	0
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs		0	0
Proceeds from asset sales	0	0	0
Other, net			0
Net cash used in (provided by) investing activities	(80,480)	(1,339,442)	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
Proceeds from issuance of Class A convertible preferred units, net		0
Repayment of senior unsecured notes	0	0
Debt issuance costs	0	0	0
Intercompany transfers	(17,638)	1,313,000	(26,264)
Issuance of common units for cash, net		0	0
Distributions to partners/owners	(123,900)	(17,500)	0
Contributions from noncontrolling interests	2,592	2,770	236
Other, net	13,121	13,847	14,504
Net cash provided by (used in) financing activities	(125,825)	1,312,117	(11,524)
Net increase in cash and cash equivalents	1,565	3,142	(1,938)
Cash and cash equivalents at beginning of period	3,805	663	2,601
Cash and cash equivalents at end of period	$ 5,370	$ 3,805	$ 663

Uncategorized Items - _IXDS

Label	Element	Value
Partners' Capital, Adjusted Balance	us-gaap_PartnersCapitalAdjustedBalance1	$ 2,013,914,000
AOCI Attributable to Parent [Member]
Partners' Capital, Adjusted Balance	us-gaap_PartnersCapitalAdjustedBalance1	(604,000)
Noncontrolling Interest [Member]
Partners' Capital, Adjusted Balance	us-gaap_PartnersCapitalAdjustedBalance1	(8,079,000)
Limited Partner [Member]
Partners' Capital, Adjusted Balance	us-gaap_PartnersCapitalAdjustedBalance1	2,022,597,000
Common Units [Member] | Limited Partner [Member]
Partners' Capital, Adjusted Balance	us-gaap_PartnersCapitalAdjustedBalance1	122,579,000
Accounting Standards Update 2014-09 [Member] | Restatement Adjustment [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(3,550,000)
Accounting Standards Update 2014-09 [Member] | AOCI Attributable to Parent [Member] | Restatement Adjustment [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	0
Accounting Standards Update 2014-09 [Member] | Noncontrolling Interest [Member] | Restatement Adjustment [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	0
Accounting Standards Update 2014-09 [Member] | Limited Partner [Member] | Restatement Adjustment [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (3,550,000)