Genesis Energy (GEL) 10-K 23 Feb 24 2023 FY Annual report Financial data

Cover

Cover - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Feb. 22, 2024	Jun. 30, 2023
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-12295
Entity Registrant Name	GENESIS ENERGY LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0513049
Entity Address, Address Line One	811 Louisiana, Suite 1200,
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
Title of 12(b) Security	Common Units
Trading Symbol	GEL
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 995.3
Document Financial Statement Error Correction	false
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001022321
Common Class A
Entity Common Stock, Shares Outstanding		122,424,321
Common Class B
Entity Common Stock, Shares Outstanding		39,997

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Auditor [Line Items]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	238
Auditor Location	Houston, Texas
EY
Auditor [Line Items]
Auditor Name		Ernst & Young LLP
Auditor Firm ID		42
Auditor Location		Houston, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 9,234	$ 7,930
Restricted cash	18,804	18,637
Accounts receivable—trade, net	759,547	721,567
Inventories	135,231	78,143
Other	41,234	26,770
Total current assets	964,050	853,047
FIXED ASSETS, at cost	6,500,897	5,865,038
Less: Accumulated depreciation	(1,972,596)	(1,768,465)
Net fixed assets	4,528,301	4,096,573
MINERALS LEASEHOLDS, net of accumulated depletion	540,520	545,122
EQUITY INVESTEES	263,829	284,486
INTANGIBLE ASSETS, net of amortization	141,537	127,320
GOODWILL	301,959	301,959
RIGHT OF USE ASSETS, net	240,341	125,277
OTHER ASSETS, net of amortization	38,241	32,208
TOTAL ASSETS	7,018,778	6,365,992
CURRENT LIABILITIES:
Accounts payable—trade	588,924	427,961
Accrued liabilities	378,523	281,146
Total current liabilities	967,447	709,107
SENIOR SECURED CREDIT FACILITY	298,300	205,400
SENIOR UNSECURED NOTES, net of debt issuance costs, discount and premium	3,062,955	2,856,312
DEFERRED TAX LIABILITIES	17,510	16,652
OTHER LONG-TERM LIABILITIES	570,197	400,617
Total liabilities	5,308,001	4,590,530
MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 23,111,918 and 25,336,778 issued and outstanding at December 31, 2023 and 2022, respectively.	813,589	891,909
COMMITMENTS AND CONTINGENCIES (Note 22)
Common units issued (in units)	122,464,318	122,579,218
Common units outstanding (in units)	122,464,318	122,579,218
PARTNERS’ CAPITAL:
Common unitholders, 122,464,318 and 122,579,218 units issued and outstanding at December 31, 2023 and 2022	$ 519,698	$ 567,277
Accumulated other comprehensive income	8,040	6,114
Noncontrolling interests	369,450	310,162
Total partners’ capital	897,188	883,553
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$ 7,018,778	$ 6,365,992
Class A Convertible Preferred Stock Units
CURRENT LIABILITIES:
Convertible preferred units outstanding (in units)	23,111,918	25,336,778
Class A convertible preferred units issued (in units)	23,111,918	25,336,778
5.875% Alkali senior secured notes due 2042
CURRENT LIABILITIES:
ALKALI SENIOR SECURED NOTES, net of debt issuance costs and discount	$ 391,592	$ 402,442

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Common units issued (in units)	122,464,318	122,579,218
Common units outstanding (in units)	122,464,318	122,579,218
SENIOR SECURED CREDIT FACILITY	$ 298,300	$ 205,400
Class A Convertible Preferred Units
Convertible preferred units issued (in units)	23,111,918	25,336,778
Convertible preferred units outstanding (in units)	23,111,918	25,336,778

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUES:
Total revenues	$ 3,176,996	$ 2,788,957	$ 2,125,476
Operating Lease, Lease Income, Statement of Income or Comprehensive Income [Extensible Enumeration]	Total revenues
COSTS AND EXPENSES:
General and administrative	$ 65,779	66,598	61,185
Depreciation, depletion and amortization	280,189	296,205	309,746
Gain on sale of assets	0	(40,000)	0
Total costs and expenses	2,847,576	2,473,945	2,049,780
OPERATING INCOME	329,420	315,012	75,696
Equity in earnings of equity investees	66,198	54,206	57,898
Interest expense	(244,663)	(226,156)	(233,724)
Other expense, net	(4,627)	(10,758)	(36,232)
Income (loss) from operations before income taxes	146,328	132,304	(136,362)
Income tax benefit (expense)	19	(3,169)	(1,670)
NET INCOME (LOSS)	146,347	129,135	(138,032)
Net income attributable to noncontrolling interests	(28,627)	(23,235)	(1,637)
Net income attributable to redeemable noncontrolling interests	0	(30,443)	(25,398)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	117,720	75,457	(165,067)
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(90,725)	(80,052)	(74,736)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS-BASIC	26,995	(4,595)	(239,803)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS-DILUTED	$ 26,995	$ (4,595)	$ (239,803)
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON UNIT:
Basic (in dollars per unit)	$ 0.22	$ (0.04)	$ (1.96)
Diluted (in dollars per unit)	$ 0.22	$ (0.04)	$ (1.96)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic (in units)	122,535	122,579	122,579
Diluted (in units)	122,535	122,579	122,579
Offshore Pipeline Transportation
REVENUES:
Total revenues	$ 382,154	$ 319,045	$ 278,459
Offshore Pipeline Transportation | Offshore pipeline transportation
REVENUES:
Total revenues	382,154	319,045	278,459
COSTS AND EXPENSES:
Cost of products and services sold	96,025	99,881	79,641
Soda and Sulfur Services
REVENUES:
Total revenues	1,734,248	1,248,085	964,632
Soda and Sulfur Services | Soda and sulfur services
REVENUES:
Total revenues	1,734,248	1,248,085	964,632
COSTS AND EXPENSES:
Cost of products and services sold	1,479,425	926,743	795,964
Marine Transportation
REVENUES:
Total revenues	327,464	293,295	190,827
Marine Transportation | Marine transportation
REVENUES:
Total revenues	327,464	293,295	190,827
COSTS AND EXPENSES:
Cost of products and services sold	218,403	228,300	156,307
Onshore Facilities and Transportation
REVENUES:
Total revenues	733,130	928,532	691,558
Onshore Facilities and Transportation | Onshore facilities and transportation
REVENUES:
Total revenues	733,130	928,532	691,558
Onshore Facilities and Transportation | Onshore facilities and transportation product costs
COSTS AND EXPENSES:
Cost of products and services sold	637,179	828,152	583,824
Onshore Facilities and Transportation | Onshore facilities and transportation operating costs
COSTS AND EXPENSES:
Cost of products and services sold	$ 70,576	$ 68,066	$ 63,113

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 146,347	$ 129,135	$ (138,032)
Other comprehensive income:
Decrease in benefit plan liability	1,926	11,721	3,758
Total Comprehensive income (loss)	148,273	140,856	(134,274)
Comprehensive income attributable to noncontrolling interests	(28,627)	(23,235)	(1,637)
Comprehensive income attributable to redeemable noncontrolling interests	0	(30,443)	(25,398)
Comprehensive income (loss) attributable to Genesis Energy, L.P.	$ 119,646	$ 87,178	$ (161,309)

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Partners’ Capital	Partners’ Capital Number of Common Units	Noncontrolling Interest	Accumulated Other Comprehensive Income (Loss)
Partner's Capital, Beginning Balance (units) at Dec. 31, 2020			122,579,000
Partners' Capital , Beginning Balance at Dec. 31, 2020	$ 818,848	$ 829,326		$ (1,113)	$ (9,365)
PARTNERS’ CAPITAL:
Net income (loss)		(165,067)		1,637
Net income (loss)	(163,430)
Cash distributions to partners	(73,548)	(73,548)
Sale of noncontrolling interest in subsidiary	419,760	125,338		294,422
Cash distributions to noncontrolling interests	(903)			(903)
Cash contributions from noncontrolling interests	703			703
Other comprehensive income (loss)	3,758				3,758
Distributions and returns attributable to Class A Convertible Preferred unitholders	(74,736)	(74,736)
Partners' Capital, Ending Balance (units) at Dec. 31, 2021			122,579,000
Partners' Capital, Ending Balance at Dec. 31, 2021	930,452	641,313		294,746	(5,607)
PARTNERS’ CAPITAL:
Net income (loss)		75,457		23,235
Net income (loss)	98,692
Cash distributions to partners	(73,548)	(73,548)
Sale of noncontrolling interest in subsidiary	0	(1,209)		1,209
Cash distributions to noncontrolling interests	(31,867)			(31,867)
Cash contributions from noncontrolling interests	22,839			22,839
Other comprehensive income (loss)	11,721				11,721
Distributions and returns attributable to Class A Convertible Preferred unitholders	(74,736)	(74,736)
Partners' Capital, Ending Balance (units) at Dec. 31, 2022			122,579,000
Partners' Capital, Ending Balance at Dec. 31, 2022	883,553	567,277		310,162	6,114
PARTNERS’ CAPITAL:
Net income (loss)		117,720		28,627
Net income (loss)	146,347
Repurchase of Class A Common Units (in shares)			(115,000)
Repurchase of Class A Common Units	(1,044)	(1,044)
Cash distributions to partners	(73,530)	(73,530)
Cash distributions to noncontrolling interests	(44,579)			(44,579)
Cash contributions from noncontrolling interests	75,240			75,240
Other comprehensive income (loss)	1,926				1,926
Distributions and returns attributable to Class A Convertible Preferred unitholders	(90,725)	(90,725)
Partners' Capital, Ending Balance (units) at Dec. 31, 2023			122,464,000
Partners' Capital, Ending Balance at Dec. 31, 2023	$ 897,188	$ 519,698		$ 369,450	$ 8,040

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 146,347	$ 129,135	$ (138,032)
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Depreciation, depletion and amortization	280,189	296,205	309,746
Gain on sale of assets	0	(40,000)	0
Amortization and write-off of debt issuance costs, premium and discount	12,889	9,271	13,716
Payments received under previously owned direct financing leases	0	0	70,000
Equity in earnings of investments in equity investees	(66,198)	(54,206)	(57,898)
Cash distributions of earnings of equity investees	64,972	55,571	57,080
Non-cash effect of long-term incentive compensation plans	25,379	17,810	8,783
Deferred and other tax liabilities	(624)	2,355	980
Cancellation of debt income	0	(8,618)	0
Unrealized losses (gains) on derivative transactions	36,635	(5,823)	30,700
Other, net	17,363	20,513	12,832
Net changes in components of operating assets and liabilities	4,174	(87,818)	30,044
Net cash provided by operating activities	521,126	334,395	337,951
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(620,019)	(424,195)	(301,395)
Cash distributions received from equity investees—return of investment	26,050	19,646	27,026
Investments in equity investees	(4,489)	(10,301)	(352)
Proceeds from asset sales	478	40,331	604
Other, net	4,332	0	0
Net cash used in investing activities	(593,648)	(374,519)	(274,117)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,183,566	971,500	776,300
Repayments on senior secured credit facility	(1,090,666)	(815,100)	(1,371,000)
Net proceeds from issuance of Alkali senior secured notes	0	408,000	0
Redemption of redeemable noncontrolling interests	0	(288,629)	0
Proceeds from issuance of senior secured notes	1,093,766	0	259,375
Repayment of senior unsecured notes	(875,969)	(72,241)	(80,859)
Net proceeds from Issuance of Preferred Units	0	0	93,100
Debt issuance costs	(24,765)	(6,019)	(12,348)
Redemption of Class A Convertible Preferred Units (Note 12)	(75,000)	0	0
Contributions from noncontrolling interests	75,240	22,839	703
Distributions to noncontrolling interests	(44,579)	(31,867)	(903)
Distributions to Class A Convertible Preferred unitholders (Note 12)	(93,930)	(74,736)	(74,736)
Distributions to common unitholders (Note 12)	(73,530)	(73,548)	(73,548)
Repurchase of Class A Common Units	(1,044)	0	0
Cash proceeds from the sale of a noncontrolling interest in a subsidiary	0	0	418,140
Other, net	904	1,500	(84)
Net cash provided by (used in) financing activities	73,993	41,699	(65,860)
Net increase (decrease) in cash and cash equivalents and restricted cash	1,471	1,575	(2,026)
Cash and cash equivalents and restricted cash at beginning of period	26,567	24,992	27,018
Cash and cash equivalents and restricted cash at end of period	$ 28,038	$ 26,567	$ 24,992

Organization

Organization	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization We are a growth-oriented master limited partnership founded in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry as well as the production of natural soda ash. Our operations are primarily located in the Gulf of Mexico, Wyoming and in the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers and industrial and commercial enterprises. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (our “Alkali Business”), refinery-related plants, storage tanks and terminals, railcars, barges and other vessels and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We currently manage our businesses through the following four divisions that constitute our reportable segments: • Offshore pipeline transportation, which includes transportation and processing of crude oil and natural gas in the Gulf of Mexico; • Soda and sulfur services involving trona and trona-based exploring, mining, processing, soda ash production, marketing, logistics 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”); • Marine transportation to provide waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America; and • Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting crude oil and petroleum products.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2023, 2022 and 2021. 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. (“Poseidon”), a 29% interest in Odyssey Pipeline L.L.C. (“Odyssey”), a 26.8% interest in Paloma Pipeline Company (“Paloma”), and a 25.7% interest in Neptune Pipeline Company, LLC, (“Neptune”). We account for our investments in these joint ventures by the equity method of accounting. See Note 9 . Noncontrolling interests Noncontrolling interests represent any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our Consolidated Balance Sheets amounts shown as noncontrolling interests in equity. See Note 1 2 for additional discussion regarding our noncontrolling interests. 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, including the estimates of future asset retirement obligations, (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, (4) estimates of variable consideration for revenue recognition, (5) estimated fair value of derivative instruments, and (6) estimated useful lives of our fixed and intangible assets (including the reserve life of our mineral leaseholds) for the use in calculating depreciation, depletion, and amortization of long-lived assets and intangible assets. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. Restricted Cash Our restricted cash balance represents a liquidity reserve account owned by GA ORRI to be held as collateral for future interest and principal payments associated with the Alkali senior secured notes. See Note 1 1 for definitions of and additional discussion regarding GA ORRI and our Alkali senior secured notes. Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and estimate an allowance for amounts that we expect will not be fully recovered. An allowance for credit losses is determined based upon historical collectability trends, recoveries, historical write-offs, and current market data for the partnership’s customers in order to estimate projected losses. 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. Within our Alkali Business, the cost of inventories are determined using the FIFO method, 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 25 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 (“AROs”) relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The estimated 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 is capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. An ongoing expense is recognized for changes in fair value of the liability as a result of the passage of time, which is recorded as accretion expense and included within operating costs in the Consolidated Statements of Operations. See Note 8 for additional information. Lease Accounting We enter into operating lease contracts for the right to utilize certain transportation equipment, facilities and equipment, and office space from third parties. For contracts that contain a lease and extend for a period greater than 12 months, we recognize a right of use asset and a corresponding lease liability on our Consolidated Balance Sheets. The present value of each lease is based on the future minimum lease payments in accordance with ASC 842 and is determined by discounting these payments using an incremental borrowing rate. From time to time, we enter into agreements in which we are lessors of our property or equipment. For operating leases, revenue is recognized upon the satisfaction of the respective performance obligation. For direct finance 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. The pipeline cost is not included in fixed assets. Refer to Note 5 for additional information. Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight-line basis. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with our credit facility 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, 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 The 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 outstanding at December 31, 2023 include only service-based awards issued to our directors. See Note 1 7 for more information. Revenue Recognition We recognize revenue across our operating segments upon the satisfaction of their respective performance obligations. Refer to Note 3 for additional details on what constitutes a performance obligation in each of our businesses. Cost of Sales and Operating Expenses 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. The most significant operating costs in our soda and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport and market the soda ash, other alkali products, NaHS and caustic soda. 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. 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, barges and other vessels, including personnel costs, fuel and maintenance of our equipment 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. 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 We use derivative instruments to hedge exposure to commodity price and fuel and freight price risk. Derivative transactions, which can include exchange-traded futures and option contracts, and commodity price swap contracts 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. As of December 31, 2023, we did not have any cash flow hedges. In addition, we determined that a certain feature within our Class A Convertible Preferred Units represented an embedded derivative, which was required to be bifurcated and recorded at fair value, with changes in fair value in respective periods recorded in our Consolidated Statements of Operations. As of September 29, 2022, the feature was no longer required to be bifurcated and valued. Gains and losses included in earnings associated with derivative transactions are presented as a component of cash flows from operating activities in the Consolidated Statements of Cashflows. See Note 1 9 for further information on these items. Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature. Pension benefits We sponsor a defined benefit plan for employees of our Alkali Business. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income (loss) Business Acquisitions For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. The fair value of the assets acquired, liabilities assumed, or noncontrolling interest in the acquiree may be adjusted during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. Refer to Note 4 Recent and Proposed Accounting Pronouncements In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” (“ASU 2023-09”), which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in ASU 2023-09 provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid information. ASU 2023-09 is effective prospectively to all annual periods beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact of this standard on our disclosures. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”), which enhances the disclosures required for operating segments in our annual and interim Consolidated Financial Statements. ASU 2023-07 is effective retrospectively for fiscal years beginning after December 15, 2023 and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact of this standard on our disclosures. All other new accounting pronouncements that have been issued, but not yet effective are currently being evaluated and at this time are not expected to have a material impact on our financial position or results of operations.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2023
Revenue Recognition [Abstract]
Revenue Recognition	Revenue Recognition Revenue from Contracts with Customers The following tables reflects the disaggregation of our revenues by major category for the years ended December 31, 2023, December 31, 2022, and December 31, 2021, respectively: Year Ended December 31, 2023 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 382,154 $ — $ 327,464 $ 54,783 $ 764,401 Product Sales — 1,639,195 — 678,347 2,317,542 Sulfur Services — 95,053 — — 95,053 $ 382,154 $ 1,734,248 $ 327,464 $ 733,130 $ 3,176,996 Year Ended December 31, 2022 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 319,045 $ — $ 293,295 $ 68,625 $ 680,965 Product Sales — 1,152,450 — 859,907 2,012,357 Sulfur Services — 95,635 — — 95,635 $ 319,045 $ 1,248,085 $ 293,295 $ 928,532 $ 2,788,957 Year Ended December 31, 2021 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 278,459 $ — $ 190,827 $ 86,711 $ 555,997 Product Sales — 863,264 — 604,847 1,468,111 Sulfur Services — 101,368 — — 101,368 $ 278,459 $ 964,632 $ 190,827 $ 691,558 $ 2,125,476 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, we recognize revenue either over time as services are being performed or at a point in time for product sales. Fee-based Revenues We provide a variety of fee-based transportation and logistics services to our customers across several of our reportable segments as outlined below. Service contracts generally contain a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over the contract period, and therefore, qualify as a single performance obligation that is satisfied over time. The customer receives and consumes the benefit of our services simultaneously with the provision of those services. Offshore Pipeline Transportation Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of natural gas or per barrel of crude oil) gathered, transported, or processed for each volume delivered. Fees are based either on contractual arrangements or tariffs regulated by the FERC. Certain of our contracts include a single performance obligation to stand ready, on a monthly basis, to provide capacity on our assets. Revenue associated with these fee-based services is recognized as volumes are delivered over the performance obligation period. In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer regardless of the volume the customer actually delivers to the platform or through the pipeline. In addition to these offshore pipeline transportation revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, our performance obligation does not change throughout the life of the contract. Therefore revenue is recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously-recognized revenue will not occur throughout the life of the contract. These estimates are reassessed at each reporting period as required. Billings to our customers are reflected at the contract rate. Differences between the amounts we bill our customers and the revenue recognized on any one contract results in the recognition of 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, terminaling services and rail unloading services, among others, primarily on a per barrel fee basis. Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff. 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 measuring 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, we have a single performance obligation to transport and deliver the barrels. 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 Soda and Sulfur Services Product sales in our soda 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: 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 still 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 is 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 entire transaction price is allocated to the performance obligation. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. For certain sales of soda ash, we offer volume inventive credits, or rebates, to customers based on the quantity purchased within a period of time as determined by the contract. The volume inventive credit is not earned by the customer until the minimum quantity of soda ash is purchased. Our policy is to reduce the transaction price allocated to these performance obligations so that our revenue is presented net of the volume incentive credits we expect to be realized. 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: 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. The transaction price 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, the transaction price is known at the time of revenue recognition and invoicing. The entire transaction price is allocated to a single performance obligation. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. Sulfur Services Our sulfur services business primarily provides sulfur removal 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 receive 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 obligation. We use units of NaHS produced during a period to measure progress as the amount we receive corresponds directly with the efforts to provide our services completed to date. The transaction price for each performance obligation is determined using the fair value of a unit of NaHS on the contract inception date for each refinery services agreement. Accordingly, we record the value of NaHS received as non-cash consideration in inventory until it is subsequently sold to our customers (see “Product Sales,” above). Contract Assets and Liabilities The table below depicts our contract asset and liability balances at December 31, 2023 and December 31, 2022: Contract Assets Contract Liabilities Other Assets Accrued Liabilities Other Long-Term Liabilities Balance at December 31, 2022 $ — $ 2,087 $ 64,478 Balance at December 31, 2023 859 11,460 112,734 For the years ended December 31, 2023, 2022, and 2021, $2.6 million, $2.6 million and $3.0 million, respectively, that was classified as a contract liability at the beginning of each period was recognized as revenue. During 2023, we deferred $11.5 million of revenue associated with a change in estimate to the measure of progress on the satisfaction of our performance obligation related to a contract within our offshore pipeline transportation segment. Additionally, we recognized $4.1 million of revenue during 2021 as a result of a contract modification related to one of our offshore pipeline transportation contracts. 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, 2023. However, ASC 606 provides the following practical expedients and exemptions that we utilized: 1) Performance obligations that are part of a contract with an expected duration of one year or less; 2) Revenue recognized from the satisfaction of performance obligations where we have a right to consideration in an amount that corresponds directly with the value provided to customers; and 3) Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that is part of a series. We apply these practical expedients and exemptions to our revenue streams recognized over time. The majority of our contracts qualify for one of these expedients or exemptions. After considering these practical expedients and identifying the remaining contract types that involve revenue recognition over a long-term period and include long term fixed consideration (adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance obligations. As it relates to our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long-term period. Therefore, we have allocated the remaining contract value (as estimated and discussed above) to future periods. In our onshore facilities and transportation segment, we have certain contractual arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines and related assets. The following chart depicts how we expect to recognize revenues for future periods related to these contracts: Offshore Pipeline Transportation Onshore Facilities and Transportation 2024 $ 119,185 $ 1,800 2025 136,326 — 2026 110,428 — 2027 66,828 — 2028 45,453 — Thereafter 124,184 — Total $ 602,404 $ 1,800

Business Consolidation

Business Consolidation	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Business Consolidation	Business Consolidation American Natural Soda Ash Corporation (“ANSAC”) ANSAC is an organization whose purpose is to promote and market the use and sale of domestically produced natural soda ash in specified countries outside of the United States. Prior to 2023, our Alkali Business and another domestic soda ash producer were the two members of ANSAC. On January 1, 2023, we became the sole member of ANSAC and assumed 100% of the voting rights of the entity, and it became a wholly owned subsidiary of Genesis. We will continue to supply levels of our soda ash produced in the Green River Basin to ANSAC to utilize their logistical and marketing capabilities as an export vehicle for our Alkali Business. We determined that ANSAC met the definition of a business and have accounted for our acquisition of ANSAC as a business combination. We have reflected the financial results of ANSAC within our soda and sulfur services segment from the date of acquisition, January 1, 2023. The purchase price has been allocated to the assets acquired and the liabilities assumed based on their respective fair values. There was no consideration transferred as a result of becoming the sole member of ANSAC. The allocation of the purchase price, as presented within our Consolidated Balance Sheet as of December 31, 2023, is summarized as follows: Cash and cash equivalents $ 4,332 Accounts receivable - trade, net 231,797 Inventories 19,522 Other current assets 14,203 Fixed assets, at cost 4,000 Right of use assets, net 93,208 Intangible assets, net of amortization 14,992 Other Assets, net of amortization 400 Accounts payable - trade (1) (228,106) Accrued liabilities (75,224) Deferred tax liabilities (1,482) Other long-term liabilities (77,642) Net Assets $ — (1) The “Accounts payable - trade” balance above includes $133.4 million of payables to Genesis at December 31, 2022 that eliminated upon consolidation in our Consolidated Balance Sheet. Inventories principally relate to finished goods (soda ash) that have been supplied by current or former members of ANSAC. “Fixed assets, at cost” relate to leasehold improvements, and “Intangible assets, net of amortization” relate to the assets supporting our logistical and marketing footprint, and both have an estimated useful life of ten years, which is consistent with the term of our primary lease facilitating our logistics operations. Right of use assets, net and our corresponding lease liabilities, which are recorded within “Accrued liabilities” and “Other long-term liabilities,” are associated with our right to use certain assets to store and load finished goods, the vessels we utilize to ship finished goods to distributors and end users, as well as office space. Our Consolidated Statement of Operations include the results of ANSAC since January 1, 2023. The following table presents selected financial information included in our Consolidated Statement of Operations for the period presented: Year Ending Revenues $ 394,948 Net Income Attributable to Genesis Energy, L.P. 8,139 The following unaudited pro forma financial information was prepared from our historical financial statements that have been adjusted to give the effect of the consolidation of ANSAC as though we had become the sole member on January 1, 2022. It is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using financial data of ANSAC 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 we become the sole member on January 1, 2022. Pro forma net income attributable to common unitholders includes the effects of distributions attributable to our Class A Preferred Units. The dilutive effect of our preferred units is calculated using the if-converted method. Year Ending December 31, 2023 2022 Pro forma consolidated financial operating results: Revenues $ 3,176,996 $ 3,246,477 Net Income Attributable to Genesis Energy, L.P. 117,720 75,457 Net Income (Loss) Attributable to Common Unitholders 26,995 (4,595) Basic and diluted earnings (loss) per common unit: As reported net income (loss) per common unit $ 0.22 $ (0.04) Pro forma net income (loss) per common unit $ 0.22 $ (0.04)

Lease Accounting

Lease Accounting	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease Accounting	Lease Accounting Lessee Arrangements We lease a variety of transportation equipment (primarily railcars and vessels), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (not greater than 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of 12 months or less are not recorded on our Consolidated Balance Sheets and we recognize lease expense for these leases on a straight-line basis over the lease term. Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally, certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as incurred and are not included in our determination of our lease liability and right of use asset. As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our incremental borrowing rate based on the information available at the inception of the lease in determining the present value of lease payments. Our lease portfolio consists of operating leases within three major categories: Transportation Equipment, Office Space and Equipment, and Facilities and Equipment. These values are recorded within “Right of Use Assets, net” on the Consolidated Balance Sheets. Current and non-current lease liabilities are recorded within “Accrued liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. Refer to the table below for our lease balances as of December 31, 2023 and December 31, 2022. Leases Classification Financial Statement Caption December 31, December 31, 2022 Assets Transportation Equipment Right of Use Assets, net $ 115,689 $ 65,375 Office Space & Equipment Right of Use Assets, net 9,014 7,238 Facilities and Equipment Right of Use Assets, net 115,638 52,664 Total Right of Use Assets, net $ 240,341 $ 125,277 Liabilities Current Accrued liabilities 29,869 17,978 Non-Current Other long-term liabilities 214,946 113,844 Total Lease Liability $ 244,815 $ 131,822 Our “Right of Use Assets, net” balance includes our unamortized initial direct costs associated with certain of our transportation equipment, office space and equipment, and facilities and equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease. Our “Right of Use Asset, net,” “Accrued liabilities” and “Other long-term liabilities” balances at December 31, 2023 include amounts related to the leases associated with our January 1, 2023 consolidation of ANSAC. See further discussion regarding the consolidation of ANSAC in Note 4 . We recorded total operating lease expense of $41.4 million, $13.6 million, and $18.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. The total operating lease expense is net of the variable railcar mileage credits we receive in our Alkali Business of $22.5 million, $22.4 million and $20.8 million for the years ended December 31, 2023, 2022, and 2021, respectively. The total operating cost includes the amounts associated with our existing lease liabilities, along with both short term lease and variable lease costs incurred during the period which are not significant to the operating lease cost individually, or in the aggregate. The following table presents the maturities of our operating lease liabilities as of December 31, 2023 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheets: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2024 $ 30,039 $ 2,355 $ 15,259 $ 47,653 2025 23,649 2,778 15,295 41,722 2026 16,550 2,453 15,347 34,350 2027 13,545 2,186 15,392 31,123 2028 10,023 1,805 15,438 27,266 Thereafter 82,215 9,585 151,204 243,004 Total Lease Payments 176,021 21,162 227,935 425,118 Less: Interest (64,394) (6,081) (109,828) (180,303) Present value of operating lease liabilities $ 111,627 $ 15,081 $ 118,107 $ 244,815 The following table presents the weighted average remaining terms and discount rates related to our right of use assets: Lease Term and Discount Rate December 31, 2023 December 31, 2022 Weighted-average remaining lease term 13.18 years 13.70 years Weighted-average discount rate 8.35% 7.75% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Year Ended Cash Flows Information 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities $ 58,979 $ 28,576 $ 33,145 Leased assets obtained in exchange for new operating lease liabilities 150,917 9,443 8,296 For the year ended December 31, 2023, cash paid for amounts included in the measurement of lease liabilities and leased assets obtained in exchange for new operating lease liabilities includes those amounts related to leases associated with our January 1, 2023 consolidation of ANSAC. See further discussion regarding the consolidation of ANSAC in Note 4 . Lessor Arrangements We have certain contracts discussed below in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties. Operating Leases During the years ended December 31, 2023, 2022, and 2021, we acted as a lessor in our revenue contracts associated with our 330,00 barrel-capacity ocean going tanker, the M/T American Phoenix, included in our marine transportation segment. Our lease revenues for this arrangement were $23.6 million, $16.4 million and $15.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. The M/T American Phoenix is under contract through mid-2027. For 2024, 2025, 2026 and through the expiration of the contract in 2027, we expect to receive undiscounted cash flows from fixed leas e payments of $28.1 million, $29.6 million, $30.7 million and $15.2 million, respectively. Our agreements generally contain clauses that may limit the use of the asset or require certain actions be taken by the lessee to maintain the asset for future performance. Direct Finance Lease We formerly held a direct finance lease of the Northeast Jackson Dome Pipeline. Under the terms of the agreement, we were paid a quarterly payment, which commenced on August 3, 2008. Subsequent to entering into the agreement, our customer, a subsidiary of Denbury, Inc., defaulted under the agreement. In 2020, we executed an agreement with our customer to accelerate the payment of $70 million of remaining, unpaid principal payments, which we received in 2021, which is included in our cash flows from operating activities on the Condensed Consolidated Statement of Cash Flows for the year ended December 31, 2021. Additionally as part of this agreement, we transferred the ownership of all of our CO 2 assets, including the Free State pipeline system, to Denbury, Inc.

Receivables

Receivables	12 Months Ended
	Dec. 31, 2023
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Receivables	Receivables Accounts receivable – trade, net consisted of the following: December 31, 2023 2022 Accounts receivable - trade $ 762,116 $ 724,419 Allowance for credit losses (2,569) (2,852) Accounts receivable - trade, net $ 759,547 $ 721,567 The following table presents the activity of our allowance for credit losses for the periods indicated: December 31, 2023 2022 2021 Balance at beginning of period $ 2,852 $ 4,825 $ 6,258 Charges to (recoveries of) costs and expenses, net 1,666 172 (902) Amounts written off (1,949) (2,145) (531) Balance at end of period $ 2,569 $ 2,852 $ 4,825

Inventories

Inventories	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Inventories	Inventories The major components of inventories were as follows: December 31, 2023 2022 Petroleum products $ — $ 56 Crude oil 22,320 6,673 Caustic soda 9,150 15,258 NaHS 17,605 7,085 Raw materials - Alkali Business 8,355 5,819 Work-in-process - Alkali Business 11,404 9,599 Finished goods, net - Alkali Business 48,706 18,772 Materials and supplies, net - Alkali Business 17,691 14,881 Total $ 135,231 $ 78,143 Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were below cost by $0.2 million as of December 31, 2023, which triggered a reduction of the value of inventory in our Consolidated Financial Statements by this amount. We recorded $2.9 million in inventory reduction adjustments as of December 31, 2022.

Fixed Assets and Asset Retireme

Fixed Assets and Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 Crude oil and natural gas pipelines and related assets $ 2,945,215 $ 2,844,288 Alkali facilities, machinery, and equipment 1,147,291 701,313 Onshore facilities, machinery, and equipment 271,271 269,949 Transportation equipment 24,913 22,340 Marine vessels 1,021,080 1,017,087 Land, buildings and improvements 293,733 231,651 Office equipment, furniture and fixtures 25,029 24,271 Construction in progress (1) 731,197 712,971 Other 41,168 41,168 Fixed assets, at cost 6,500,897 5,865,038 Less: Accumulated depreciation (1,972,596) (1,768,465) Net fixed assets $ 4,528,301 $ 4,096,573 (1) Construction in progress primarily relates to our ongoing offshore growth capital projects, which are expected to be completed in 2024 and 2025. Mineral Leaseholds Our Mineral Leaseholds, relating to our Alkali Business, consist of the following: December 31, 2023 December 31, 2022 Mineral leaseholds $ 566,019 $ 566,019 Less: Accumulated depletion (25,499) (20,897) Mineral leaseholds, net $ 540,520 $ 545,122 Depreciation expense was $263.5 million, $281.4 million and $295.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. Depletion expense was $4.6 million, $3.9 million, and $3.6 million for the years ended December 31, 2023, 2022 and 2021, respectively. Asset Sales and Divestitures On April 29, 2022, we entered into an agreement to sell the Independence Hub platform to a producer group in the Gulf of Mexico for gross proceeds of $40.0 million, of which $8.0 million, or 20%, was attributable and paid to our noncontrolling interest holder. For the year ended December 31, 2022, we recorded a gain of $40.0 million recorded in “Gain on sale of asset” on the Consolidated Statement of Operations, of which $8.0 million, or 20%, is included in “Net income attributable to noncontrolling interests” on the Consolidated Statement of Operations, as the platform asset sold had no book value at the time of the sale. 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, 2020 $ 176,852 Accretion expense 10,038 Revisions in timing and estimated costs of AROs 35,735 Acquisitions 3,008 Settlements (4,727) December 31, 2021 $ 220,906 Accretion expense 13,092 Revisions in timing and estimated costs of AROs 11,216 Settlements (16,641) December 31, 2022 $ 228,573 Accretion expense 12,040 Revisions in timing and estimated costs of AROs 3,185 Settlements (90) December 31, 2023 $ 243,708

Equity Investees

Equity Investees	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022, the unamortized differences in carrying value totaled $291.4 million and $305.6 million, respectively. We amortize the differences in carrying value as a change in equity earnings. The following table presents information included in our Consolidated Financial Statements related to our equity investees: Year Ended December 31, 2023 2022 2021 Genesis’ share of operating earnings $ 80,461 $ 68,469 $ 73,389 Amortization of differences attributable to Genesis’ carrying value of equity investments (14,263) (14,263) (15,491) Net equity in earnings $ 66,198 $ 54,206 $ 57,898 Distributions earned (1) $ 90,833 $ 75,406 $ 84,106 (1) Distributions attributab le to the respective period and received within 15 days subsequent to the respective period end. Poseidon’s revolving credit facility

Intangible Assets, Goodwill and

Intangible Assets, Goodwill and Other Assets	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022: December 31, 2023 December 31, 2022 Weighted Gross Accumulated Carrying Gross Accumulated Carrying Offshore pipeline contract intangibles 19 158,101 70,036 88,065 158,101 61,715 96,386 Other 10 70,974 17,502 53,472 45,191 14,257 30,934 Total $ 229,075 $ 87,538 $ 141,537 $ 203,292 $ 75,972 $ 127,320 The offshore pipeline contract intangibles relate to customer contracts surrounding certain transportation agreements with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline. We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. All of our current intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $11.6 million, $10.3 million and $10.3 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2024 2025 2026 2027 2028 Offshore pipeline contract intangibles $ 8,321 $ 8,321 $ 8,321 $ 8,321 $ 8,321 Other 6,504 6,244 5,932 5,485 5,235 Total $ 14,825 $ 14,565 $ 14,253 $ 13,806 $ 13,556 Goodwill The carrying amount of goodwill in our soda and sulfur services segment was $301.9 million at December 31, 2023 and December 31, 2022. We have not recognized any impairment losses related to goodwill for any of the periods presented. Other Assets Other assets consisted of the following: December 31, 2023 2022 Deferred marine charges, net (1) $ 19,651 $ 20,503 Unamortized debt issuance costs on senior secured credit facility 5,676 2,591 Other deferred charges, net 12,914 9,114 Other assets, net of amortization $ 38,241 $ 32,208 (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 ).

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	Debt At December 31, 2023 and 2022, our obligations under debt arrangements consisted of the following: December 31, 2023 December 31, 2022 Principal Unamortized Premium, Discount and Debt Issuance Costs Net Value Principal Unamortized Premium and Debt Issuance Costs Net Value Senior secured credit facility-Revolving Loan (1) $ 298,300 $ — $ 298,300 $ 205,400 $ — $ 205,400 5.625% senior unsecured notes due 2024 — — — 341,135 1,249 339,886 6.500% senior unsecured notes due 2025 — — — 534,834 3,265 531,569 6.250% senior unsecured notes due 2026 339,310 1,746 337,564 339,310 2,481 336,829 8.000% senior unsecured notes due 2027 981,245 3,549 977,696 981,245 4,956 976,289 7.750% senior unsecured notes due 2028 679,360 6,121 673,239 679,360 7,621 671,739 8.250% senior unsecured notes due 2029 600,000 17,202 582,798 — — — 8.875% senior unsecured notes due 2030 500,000 8,342 491,658 — — — 5.875% Alkali senior secured notes due 2042 (2) 425,000 21,791 403,209 425,000 22,558 402,442 Total long-term debt $ 3,823,215 $ 58,751 $ 3,764,464 $ 3,506,284 $ 42,130 $ 3,464,154 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in “Other Assets, net of amortization” on the Consolidated Balance Sheets) were $5.7 million and $2.6 million as of December 31, 2023 and December 31, 2022, respectively. (2) As of December 31, 2023, $11.6 million of the principal balance is considered current and included within “Accrued liabilities” on the Condensed Consolidated Balance Sheet. Senior Secured Credit Facility On February 17, 2023, we entered into the Sixth Amended and Restated Credit Agreement (our “credit agreement” to replace our Fifth Amended and Restated Credit Agreement (the “old credit agreement”). Our credit agreement provides for a $850 million senior secured revolving credit facility. The credit agreement matures on February 13, 2026, subject to extension at our request for one As of December 31, 2023, the key terms for rates under our senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows: • Revolving credit facility: The interest rate on borrowings may be based on an alternate base rate or Term Secured Overnight Financing Rate (“SOFR”), at our option. Interest on alternate base rate loans is equal to the sum of (a) the highest of (i) the prime rate in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% and (iii) the Adjusted Term SOFR (as defined in our credit agreement) for a one-month tenor in effect on such day plus 1% and (b) the applicable margin. The Adjusted Term SOFR is equal to the sum of (a) the Term SOFR rate (as defined in our credit agreement) for such period plus (b) the Term SOFR Adjustment of 0.1% plus (c) the applicable margin. The applicable margin varies from 2.25% to 3.50% on Term SOFR borrowings and from 1.25% to 2.50% 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, 2023, the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Term SOFR borrowings based on our leverage ratio. • Letter of credit fees range from 2.25% to 3.50% based on our leverage ratio as computed under the credit agreement. The rate can fluctuate quarterly. At December 31, 2023, our letter of credit rate was 2.75%. • We pay a commitment fee on the unused portion of the senior secured credit facility. The commitment fee on the unused committed amount will range from 0.30% to 0.50% per annum depending on our leverage ratio. At December 31, 2023, our commitment fee rate on the unused committed amount was 0.50%. • We have the ability to increase the aggregate size of the senior secured credit facility by an additional $200 million subject to lender consent and certain other customary conditions. At December 31, 2023, we had $298.3 million borrowed under our senior secured credit facility, with $19.3 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100.0 million of the capacity to be used for letters of credit, of which $4.5 million was outstanding at December 31, 2023. Due to the revolving nature of loans under our senior secured credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of our credit agreement. The total amount available for borrowings under our senior secured credit facility at December 31, 2023 was $547.2 million, subject to compliance with our covenants. Our credit agreement does not include a “borrowing base” limitation except with respect to our inventory loans. Alkali Senior Secured Notes Issuance and Related Transactions On May 17, 2022, Genesis Energy, L.P., through its newly created wholly-owned unrestricted subsidiary, GA ORRI, LLC (“GA ORRI”), issued $425 million principal amount of our 5.875% senior secured notes due 2042 (the “Alkali senior secured notes”) to certain institutional investors (the “Notes Offering”), secured by GA ORRI’s fifty-year 10% limited term overriding royalty interest in substantially all of the Alkali Business’ trona mineral leases (the “ORRI Interests”). Interest payments are due on the last day of each quarter with the initial interest payment made on June 30, 2022. The agreement governing the Alkali senior secured notes also requires principal repayments on the last day of each quarter commencing with the first quarter of 2024. Principal repayments totaling $11.6 million, $13.1 million, $14.2 million, $14.6 million, and $15.7 million are due in 2024, 2025, 2026, 2027 and 2028 respectively, with the remaining quarterly principal repayments due thereafter through March 31, 2042. We are required to maintain a certain level of cash in a liquidity reserve account (owned by GA ORRI) to be held as collateral for future interest and principal payments as calculated and described in the agreement governing the Alkali senior secured notes. As of December 31, 2023 our liquidity reserve account had a balance of $18.8 million, which is classified as “Restricted cash” on the Consolidated Balance Sheets. The issuance generated net proceeds of $408 million, net of the issuance discount of $17 million. We used a portion of the net proceeds from the issuance to fully redeem the outstanding Alkali Holdings preferred units (as defined and further discussed in Note 1 2 ) and utilized the remainder to repay a portion of the outstanding borrowings under our senior secured credit facility as well as fund our liquidity reserve account. Additionally, on May 17, 2022, we entered into an amendment to our old credit agreement. This amendment also designated GA ORRI and its direct parent, GA ORRI Holdings, LLC (“GA ORRI Holdings”), as unrestricted subsidiaries under our old credit agreement. We also designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries under the indentures governing our senior unsecured notes. On May 17, we also reclassified the subsidiaries originally held by our Alkali Business as restricted subsidiaries under our old credit agreement and under the indentures governing our senior unsecured notes. Senior Unsecured Notes On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due June 15, 2024 (the “2024 Notes”). On January 24, 2023, approximately $316 million of these notes were validly tendered and repaid upon the issuance of our $500 million senior unsecured notes due in 2030 (the “2030 Notes” as defined and further discussed below). On January 26, 2023, we issued a notice of redemption for the remaining principal of approximately $25 million of the 2024 Notes in accordance with the terms and conditions of the indenture governing the notes, and discharged the indebtedness with respect to the 2024 Notes on February 14, 2023. We incurred a loss of $1.8 million on the tender and redemption of the 2024 Notes, inclusive of our transactions costs and write-off of the related unamortized debt issuance costs, which is recorded as “Other expense, net” in our Consolidated Statement of Operations for the year ended December 31, 2023. 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”). On December 7, 2023, approximately $514 million of these notes were validly tendered and repaid upon the issuance of our $600 million senior unsecured notes due in 2029 (the “2029 Notes” as defined and further discussed below). On December 8, 2023, we issued a notice of redemption for the remaining principal of approximately $21 million of our 2025 Notes, and discharged the indebtedness with respect to the 2025 Notes on December 28, 2023 by depositing the redemption amount with the trustee of the 2025 Notes, all in accordance with the terms and conditions of the indenture governing the 2025 Notes. We incurred a loss of $2.8 million on the tender and redemption of the 2025 Notes, inclusive of our transactions costs and write-off of the related unamortized debt issuance costs, which is recorded as “Other expense, net” in our Consolidated Statement of Operations for the year ended December 31, 2023. 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 approximately $442 million, net of issuance costs incurred. We used approximately $205 million of the net proceeds to redeem the portion of the 5.75% senior unsecured notes due February 15, 2021 that were validly tendered and the remaining net proceeds to repay a portion of the borrowings outstanding under our senior secured credit facility. On January 16, 2020, we issued $750 million in aggregate principal amount of our 7.75% senior unsecured notes due February 1, 2028 (the “2028 Notes”). Interest payments are due February 1 and August 1 of each year with the initial interest payment due on August 1, 2020. That issuance generated net proceeds of approximately $737 million net of issuance costs incurred. We used approximately $555 million of the net proceeds to redeem a portion of our 6.75% senior unsecured notes due August 1, 2022 (including principal, accrued interest and tender premium) that were validly tendered, and the remaining net proceeds were used to repay a portion of the borrowings outstanding under our senior secured credit facility. On December 17, 2020, we issued $750 million in aggregate principal amount of our 8.00% senior unsecured notes due January 15, 2027 (the “2027 Notes”). Interest payments are due January 15 and July 15 of each year with the initial interest payment due on July 15, 2021. That issuance generated net proceeds of approximately $737 million net of issuance costs incurred. We used approximately $317 million of the net proceeds to repay the portion of the 6.00% 2023 Notes (including principal, accrued interest and tender premium) that were validly tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior secured credit facility. On April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of the 2027 Notes. The additional $250 million of notes have identical terms as (other than with respect to the issue price) and constitute part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the borrowings outstanding under our senior secured credit facility. On January 25, 2023, we issued $500 million in aggregate principal amount of 8.875% senior unsecured notes due April 15, 2030 (the “2030 Notes”). Interest payments are due April 15 and October 15 of each year with the initial interest payment due on October 15, 2023. The issuance generated proceeds of approximately $491 million, net of issuance costs incurred. The net proceeds were used to purchase approximately $316 million of our existing 5.625% senior unsecured notes due June 15, 2024 (the “2024 Notes”), and pay the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that ended January 24, 2023, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior secured credit facility and for general partnership purposes. On January 26, 2023, we issued a notice of redemption for the remaining principal of approximately $25 million of our 2024 Notes, and discharged the indebtedness with respect to the 2024 Notes on February 14, 2023 by depositing the redemption amount with the trustee of the 2024 Notes for redemption of the 2024 Notes on February 25, 2023, all in accordance with the terms and conditions of the indenture governing the 2024 Notes. On December 7, 2023, we issued $600 million in aggregate principal amount of our 8.25% senior unsecured notes due January 15, 2029 (the “2029 Notes). Interest payments are due January 15 and July 15 of each year with the initial interest payment due on July 15, 2024. The issuance of our 2029 Notes generated net proceeds of approximately $583 million, net of the discount of $6.2 million and issuance costs incurred. The net proceeds were used to purchase approximately $514 million of approximately $535 million then outstanding on our 2025 Notes and pay the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that ended December 6, 2023. On December 8, 2023 we issued a notice of redemption for the remaining principal of approximately $21 million of our 2025 Notes, and discharged the indenture governing the 2025 Notes as to all 2025 Notes issued thereunder on December 28, 2023 by depositing the redemption amount in trust with the trustee of the 2025 Notes for redemption of the 2025 Notes, all in accordance with the terms and conditions of the indenture governing the 2025 Notes. 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: 2026 Notes 2027 Notes 2028 Notes 2029 Notes 2030 Notes Redemption right beginning on February 15, 2021 January 15, 2024 February 1, 2023 January 15, 2026 April 15, 2026 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to N/A N/A N/A January 15, 2026 April 15, 2026 . During the year ended December 31, 2022, we repurchased $80.9 million of our senior unsecured notes on the open market and recorded cancellation of debt income of $8.6 million. This is recorded within “Other expense, net” in our Consolidated Statements of Operations. Guarantees of our 2026, 2027, 2028, 2029 and 2030 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. Our $3.1 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 (the “Guarantor Subsidiaries”), except GA ORRI and GA ORRI Holdings, and certain other subsidiaries. The non-guarantor subsidiaries are indirectly owned by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets, other than the ORRI Interests, that we use to operate our business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries. Covenants and Compliance Our credit agreement contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit agreement, we are required to meet three primary financial metrics—a maximum consolidated leverage ratio, a maximum consolidated senior secured leverage ratio and a minimum consolidated 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 transactions. In general, our consolidated leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to our Adjusted Consolidated EBITDA (as defined and adjusted in accordance with the credit agreement). Our consolidated senior secured leverage ratio calculation compares our consolidated senior secured funded debt (including outstanding borrowings on the senior secured credit facility) to our Adjusted Consolidated EBITDA (as defined and adjusted in accordance with the credit agreement), and our minimum consolidated interest coverage ratio compares our Adjusted Consolidated EBITDA (as defined and adjusted in accordance with the credit agreement) to our Consolidated interest expense (as defined and adjusted in accordance with the credit agreement). As of December 31, 2023, under our credit agreement, the permitted maximum consolidated leverage ratio is 5.50x for the remainder of the term. The permitted maximum consolidated senior secured leverage ratio is 2.50x and the minimum consolidated interest coverage ratio is 2.50x for the remaining term of the credit agreement. In addition, our credit agreement and the indentures governing the senior unsecured 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 agreement, our ability to make distributions of “available cash” is not restricted. As of December 31, 2023, we were in compliance with the financial covenants contained in our credit agreement and indentures.

Partners' Capital, Mezzanine Eq

Partners' Capital, Mezzanine Equity and Distributions	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Partners' Capital, Mezzanine Equity and Distributions	Partners’ Capital, Mezzanine Equity and Distributions At December 31, 2023, our outstanding equity consisted of 122,424,321 Class A Common Units and 39,997 Class B Common Units. The Class A Common Units are traditional common units in us. The Class B Common Units have the voting and distribution rights equivalent to those of the Class A Common Units, however, the Class B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain circumstances, subject to certain exceptions. At December 31, 2023, we had 23,111,918 Class A Convertible Preferred Units outstanding, which are discussed below in further detail. In an effort to return capital to our investors, we announced a common equity repurchase program (the “Repurchase Program”) on August 8, 2023. The Repurchase Program authorizes the repurchase from time to time of up to 10% of our then outstanding Class A Common Units, or 12,253,922 units, via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. These repurchases may be made pursuant to a repurchase plan or plans that comply with Rule 10b5-1 under the Securities Exchange Act of 1934. The Repurchase Program will be reviewed no later than December 31, 2024 and may be suspended or discontinued at any time prior thereto. The Repurchase Program does not create an obligation for us to acquire a particular number of Class A Common Units and any Class A Common Units repurchased will be canceled. During 2023, we repurchased and canceled a total of 114,900 Class A Common Units at an average price of approximately $9.09 per unit for a total purchase price of $1.0 million, including commissions, which is reflected as a reduction to the carrying value of our “Partners’ Capital - Common unitholders” on our Consolidated Balance Sheet. 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 common unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter: • less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to: • provide for the proper conduct of our business; • comply with applicable law, any of our debt instruments, or other agreements; or • provide funds for distributions to our common and preferred unitholders for any one or more of the next four quarters; • plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings. Working capital borrowings are generally borrowings that are made under our senior secured credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. We paid the following cash distributions to common unitholders: Distribution For Date Paid Per Unit Amount Total Amount 2021 1 st Quarter May 14, 2021 $ 0.1500 $ 18,387 2 nd Quarter August 13, 2021 $ 0.1500 $ 18,387 3 rd Quarter November 12, 2021 $ 0.1500 $ 18,387 4 th Quarter February 14, 2022 $ 0.1500 $ 18,387 2022 1 st Quarter May 13, 2022 $ 0.1500 $ 18,387 2 nd Quarter August 12, 2022 $ 0.1500 $ 18,387 3 rd Quarter November 14, 2022 $ 0.1500 $ 18,387 4 th Quarter February 14, 2023 $ 0.1500 $ 18,387 2023 1 st Quarter May 15, 2023 $ 0.1500 $ 18,387 2 nd Quarter August 14, 2023 $ 0.1500 $ 18,387 3 rd Quarter November 14, 2023 $ 0.1500 $ 18,370 4 th Quarter February 14, 2024 $ 0.1500 $ 18,370 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. We did not issue any Class A Common Units or Class B Common Units during the periods presented. Class A Convertible Preferred Units On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units (our “Class A Convertible 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 Class A Convertible Preferred Units. Our Class A Convertible Preferred Units rank 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 Class A Convertible 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 Class A Convertible Preferred Units. From time to time after September 1, 2020, we have the right to cause the conversion of all or a portion of outstanding Class A Convertible 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 Class A Convertible Preferred Units in any consecutive twelve-month period. At any time after September 1, 2020, if we have fewer than 592,768 of our Class A Convertible Preferred Units outstanding, we will have the right to convert each outstanding Class A Convertible 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 Class A Convertible 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 Class A Convertible 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 Class A Convertible 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 Class A Convertible Preferred Units may elect to (a) convert all of its Class A Convertible 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 Class A Convertible 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 Class A Convertible Preferred Units or (d) require us to exchange our Class A Convertible 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 Class A Convertible 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. On September 29, 2022 (the “election date”), the Rate Reset Election was elected by the holders of our Class A Convertible Preferred Units. Upon issuance and up until the election date, each of our Class A Convertible Preferred Units accumulated 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). On the election date, the holders of the Class A Convertible Preferred Units elected to reset the rate to 11.24%, the sum of the three-month LIBOR of 3.74% plus 750 basis points, yielding a quarterly distribution $0.9473 per preferred unit beginning with the fourth quarter of 2022. We elected to pay all distributions from inception through March 1, 2019 with additional Class A Convertible Preferred Units. For the quarter ended March 31, 2019, we paid a portion of our distribution in cash, and a portion in Class A Convertible Preferred Units. For each quarter ending after March 1, 2019, we paid all distribution amounts in respect of our Class A Convertible Preferred Units in cash. Each holder of our Class A Convertible Preferred Units may elect to convert all or any portion of its Class A Convertible 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 Class A Convertible 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 Class A Convertible Preferred Units and parity securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our Class A Convertible 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. 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 Class A Convertible 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 Class A Convertible 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. Accounting for the Class A Convertible Preferred Units Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event that is outside of our control. Therefore, we present them as temporary equity in the mezzanine section of the Consolidated Balance Sheets. We initially recognized our Class A Convertible Preferred Units at their issuance date fair value, net of issuance costs, as they were not redeemable and we did not have plans or expect any events that constitute a change of control in our partnership agreement. From the date of issuance through the election date, the Rate Reset Election was bifurcated and accounted for separately as an embedded derivative and recorded at fair value at each reporting period in “Other long-term liabilities” in our Consolidated Balance Sheets. As of the election date, the feature within the Class A Convertible Preferred Units that required bifurcation no longer existed and we have adjusted the carrying value of the Class A Convertible Preferred Units to include the fair value of the previously bifurcated amount at the election date. Refer to Note 1 9 and Note 20 for additional discussion. As of December 31, 2023, we will not be required to further adjust the carrying amount of our Class A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our Class A Convertible Preferred Units to the redemption value over a period of time comprising the date the feature first becomes probable and the date the units can first be redeemed. We paid the following cash distributions to our Class A Convertible Preferred unitholders: Distribution For Date Paid Per Unit Total 2021 1 st Quarter May 14, 2021 $ 0.7374 $ 18,684 2 nd Quarter August 13, 2021 $ 0.7374 $ 18,684 3 rd Quarter November 12, 2021 $ 0.7374 $ 18,684 4 th Quarter February 14, 2022 $ 0.7374 $ 18,684 2022 1 st Quarter May 13, 2022 $ 0.7374 $ 18,684 2 nd Quarter August 12, 2022 $ 0.7374 $ 18,684 3 rd Quarter November 14, 2022 $ 0.7374 $ 18,684 4 th Quarter February 14, 2023 $ 0.9473 $ 24,002 2023 1 st Quarter May 15, 2023 $ 0.9473 $ 24,002 2 nd Quarter August 14, 2023 $ 0.9473 $ 23,314 3 rd Quarter November 14, 2023 $ 0.9473 $ 22,612 4 th Quarter February 14, 2024 $ 0.9473 $ 21,894 On April 3, 2023, July 3, 2023, and October 3, 2023 we entered into purchase agreements with the Class A Convertible Preferred unitholders whereby we redeemed a total of 2,224,860 Class A Convertible Preferred Units (the “Redeemed Units”) at an average purchase price of $33.71 per unit. The Redeemed Units had a carrying value of $35.20 per unit resulting in returns attributable to the Class A Convertible Preferred Units of $3.2 million for the year ended December 31, 2023. There were 23,111,918 Class A Convertible Preferred Units outstanding as of December 31, 2023. Net Income Attributable to Genesis Energy, L.P. is adjusted for distributions and returns attributable to the Class A Convertible Preferred Units that accumulate in the period. Net income attributable to Genesis Energy, L.P. for the year ended 2023 was reduced by $90.7 million due to Class A Convertible Preferred Unit distributions of $93.9 million that accumulated during the period, offset partially by returns of $3.2 million discussed above. Net income (loss) attributable to Genesis Energy, L.P. was reduced by $80.1 million, and $74.7 million for the years ended 2022 and 2021, respectively, due to Class A Convertible Preferred Unit distributions that accumulated during each period. Redeemable Noncontrolling Interests On September 23, 2019, we, through a subsidiary, Genesis Alkali Holdings Company, LLC (“Alkali Holdings”), the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business, including its Granger facility near Green River, Wyoming, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the “LLC Agreement”) and a Securities Purchase Agreement (the “Securities Purchase Agreement”) whereby certain investment fund entities affiliated with Blackstone Alternative Credit Advisors LP, formerly known as “GSO Capital Partners LP” (collectively, “BXC”) purchased $55.0 million of preferred units (or 55,000 preferred units) and committed to purchase, during a three-year commitment period, up to a total of $350.0 million of preferred units (or 350,000 preferred units) in Alkali Holdings (the “Alkali Holdings preferred units”). Alkali Holdings utilized the net proceeds from the preferred units to fund a portion of the anticipated cost of the Granger Optimization Project. On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the Granger Optimization Project by one year. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period was increased to four years, and the total commitment of BXC was increased to $351.8 million preferred units (or 351,750 preferred units) in Alkali Holdings. From time to time after we had drawn at least $251.8 million, we had the option to redeem the outstanding preferred units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a predetermined fixed internal rate of return amount (“IRR”) or a multiple of invested capital metric (“MOIC”), net of cash distributions paid to date (“Base Preferred Return Amount”). Additionally, if all outstanding preferred units were redeemed, we had not drawn at least $251.8 million, and BXC was not a “defaulting member” under the LLC Agreement, BXC had the right to a make-whole amount on the number of undrawn preferred units. On May 17, 2022 (the “Redemption Date”), we fully redeemed the 251,750 outstanding Alkali Holdings preferred units at a Base Preferred Return Amount of $288.6 million utilizing a portion of the proceeds we received from the issuance of our Alkali senior secured notes ( Note 1 1 ). As of December 31, 2023 and 2022, there were no Alkali Holdings preferred units outstanding. Accounting for Redeemable Noncontrolling Interests Classification Prior to the Redemption Date, the Alkali Holdings preferred units issued and outstanding were accounted for as a redeemable noncontrolling interest in the mezzanine section on our Consolidated Balance Sheets due to the redemption features for a change of control. Initial and Subsequent Measurement We recorded the Alkali Holdings preferred units at their issuance date fair value, net of issuance costs. The fair value of the Alkali Holdings preferred units was approximately $270.1 million as of May 16, 2022, which represented the carrying amount based on the issued and outstanding Alkali Holdings preferred units most probable redemption event on the six and a half year anniversary of the closing, which was the IRR measure accreted using the effective interest method to the redemption value as of each reporting date. On May 16, 2022, certain events occurred that made it probable that an early redemption event on the Alkali Holdings preferred units would occur and the outstanding preferred units would be redeemed at the MOIC, as it was greater than the IRR at the time of the redemption. This required the Company to revalue the Alkali Holdings preferred units to the redemption amount of $288.6 million, which represented the MOIC, net of cash distributions (including tax distributions) paid to date. Net income Attributable to Genesis Energy, L.P. for the year ended December 31, 2022 includes $30.4 million of adjustments, of which $10.0 million was allocated to the PIK distributions on the outstanding preferred units and $1.9 million was attributable to redemption accretion value adjustments, and $18.5 million was attributable to a change in the Base Preferred Return Amount of the Alkali Holdings preferred units. Net Loss Attributable to Genesis Energy, L.P. for the year ended December 31, 2021 includes $25.4 million of adjustments, of which $21.3 million was allocated to the PIK distributions on the outstanding preferred units and $4.1 million was attributable to redemption accretion value adjustments. The following table shows the change in our redeemable noncontrolling interests from December 31, 2021 to December 31, 2022: Balance as of December 31, 2021 $ 259,568 Issuance of preferred units, net of issuance costs (1) 5,249 PIK distribution 9,993 Redemption accretion 1,908 Tax distributions (1) (6,631) Adjustment to Base Preferred Return Amount 18,542 Redemption of preferred units on May 17, 2022 (288,629) Balance as of December 31, 2022 — (1) We issued 5,356 Alkali Holdings preferred units to BXC to satisfy the Company’s obligation to pay tax distributions during 2022. Noncontrolling Interests On November 17, 2021, we, through a subsidiary, sold 36% of the membership interests in CHOPS for proceeds of approximately $418 million. We retained 64% of the membership interests in CHOPS and remain the operator of the CHOPS pipeline and associated assets. We also own an 80% membership interest in Independence Hub, LLC. On April 29, 2022, we entered into an agreement to sell the Independence Hub platform to a producer group in the Gulf of Mexico for gross proceeds of $40.0 million, of which $8.0 million, or 20%, was attributable and paid to our noncontrolling interest holder. For the year ended December 31, 2022, we recorded a gain of $40.0 million recorded in “Gain on sale of asset” on the Consolidated Statement of Operations, of which $8.0 million, or 20%, is attributable to our noncontrolling interest holder, as the platform asset sold had no book value at the time of the sale. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our Consolidated Balance Sheets amounts shown as noncontrolling interests in equity.

Net Income (Loss) Per Common Un

Net Income (Loss) Per Common Unit	12 Months Ended
	Dec. 31, 2023
Net Income per Common Unit [Abstract]
Net Income (Loss) Per Common Unit	Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed by dividing Net Income (Loss) Attributable to Genesis Energy, L.P., after considering income attributable to our Class A preferred unitholders, by the weighted average number of common units outstanding. The dilutive effect of the Class A Convertible Preferred Units is calculated using the if-converted method. Under the if-converted method, the Class A Convertible Preferred Units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the years ended December 31, 2023, 2022, and 2021, the effect of the assumed conversion of our Class A Convertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit. The following table reconciles Net income (loss) and weighted average units used in computing basic and diluted Net income (loss) per common unit (in thousands): Year Ended 2023 2022 2021 Net income (loss) attributable to Genesis Energy L.P. $ 117,720 $ 75,457 $ (165,067) Less: Accumulated distributions attributable to Class A Convertible Preferred Units (90,725) (80,052) (74,736) Net income (loss) available to common unitholders $ 26,995 $ (4,595) $ (239,803) Weighted average outstanding units 122,535 122,579 122,579 Basic and diluted net income (loss) per common unit $ 0.22 $ (0.04) $ (1.96)

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information We currently manage our businesses through four divisions that constitute our reportable segments: • Offshore pipeline transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico; • Soda and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing, logistics 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; • Marine transportation – marine transportation to provide waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America. • Onshore facilities and transportation – terminaling, blending, storing, marketing and transporting crude oil and petroleum products; and 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 gains and charges, such as depreciation, depletion, amortization and accretion), segment general and administrative expenses, all of which are net of the effects of our noncontrolling interests, plus our equity in distributable cash generated by our equity investees and unrestricted subsidiaries. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation plan and includes the non-income portion of payments received under our previously owned direct financing lease. 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 Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Total Year Ended December 31, 2023 Segment Margin (1) $ 406,672 $ 282,014 $ 110,423 $ 27,953 $ 827,062 Capital expenditures (2) $ 410,237 $ 219,393 $ 42,681 $ 19,018 $ 691,329 Revenues: External customers $ 377,842 $ 1,743,327 $ 327,464 $ 728,363 $ 3,176,996 Intersegment (3) 4,312 (9,079) — 4,767 $ — Total revenues of reportable segments $ 382,154 $ 1,734,248 $ 327,464 $ 733,130 $ 3,176,996 Year Ended December 31, 2022 Segment Margin (1) $ 363,373 $ 306,718 $ 66,209 $ 33,755 $ 770,055 Capital expenditures (2) $ 241,446 $ 174,518 $ 39,084 $ 5,878 $ 460,926 Revenues: External customers $ 319,045 $ 1,258,236 $ 292,925 $ 918,751 $ 2,788,957 Intersegment (3) — (10,151) 370 9,781 $ — Total revenues of reportable segments $ 319,045 $ 1,248,085 $ 293,295 $ 928,532 $ 2,788,957 Year Ended December 31, 2021 Segment Margin (1) $ 317,560 $ 166,773 $ 34,572 $ 98,824 $ 617,729 Capital expenditures (2) $ 50,546 $ 227,118 $ 34,456 $ 4,609 $ 316,729 Revenues: External customers $ 278,459 $ 973,354 $ 188,011 $ 685,652 $ 2,125,476 Intersegment (3) — (8,722) 2,816 5,906 $ — Total revenues of reportable segments $ 278,459 $ 964,632 $ 190,827 $ 691,558 $ 2,125,476 (1) A reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin to for each year is presented below. (2) 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 contributions to equity investees, if any. (3) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions. Total assets by reportable segment were as follows: December 31, 2023 December 31, 2022 Offshore pipeline transportation $ 2,580,032 $ 2,290,488 Soda and sulfur services 2,705,350 2,358,086 Marine Transportation 645,020 681,231 Onshore facilities and transportation 1,019,113 981,354 Other assets 69,263 54,833 Total consolidated assets $ 7,018,778 $ 6,365,992 Reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin: Year Ended 2023 2022 2021 Net income (loss) attributable to Genesis Energy, L.P. $ 117,720 $ 75,457 $ (165,067) Corporate general and administrative expenses 73,876 71,820 61,287 Depreciation, depletion, amortization and accretion 291,731 307,519 315,896 Interest expense 244,663 226,156 233,724 Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income (1) 24,635 21,199 26,207 Other non-cash items (2) 13,488 (8,315) 30,907 Distributions from unrestricted subsidiaries not included in income (3) — 32,000 70,000 Cancellation of debt income ( Note 1 1 ) — (8,618) — Loss on extinguishment of debt (Note 1 1 ) 4,627 794 1,627 Differences in timing of cash receipts for certain contractual arrangements (4) 56,341 51,102 15,482 Gain on sale of asset, net to our ownership interest (Note 8 ) — (32,000) — Change in provision for leased items no longer in use — (671) 598 Income tax expense (benefit) (19) 3,169 1,670 Redeemable noncontrolling interest redemption value adjustments (5) — 30,443 25,398 Total Segment Margin $ 827,062 $ 770,055 $ 617,729 (1) Includes distributions attributable to the period and received during or promptly following such period. (2) 2023 includes unrealized losses of $36.7 million from the valuation of our commodity derivative transactions (excluding fair value hedges). 2022 includes unrealized gains of $24.4 million from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized losses of $18.6 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. 2021 includes unrealized gains of $0.1 million from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized losses of $30.8 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. (3) 2022 includes $32.0 million in cash receipts associated with the sale of the Independence Hub platform by our 80% owned unrestricted subsidiary (as defined under our credit agreement), Independence Hub, LLC. 2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. (4) 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. (5) 2022 includes PIK distributions and accretion on the redemption feature of our Alkali Holdings preferred units, and valuation adjustments to the redemption feature as the associated Alkali Holdings preferred units were redeemed during the year ended December 31, 2022. 2021 includes PIK distributions and accretion on the redemption feature attributable to our Alkali Holdings preferred units. Refer to Note 1 2 for additional information.

Transactions with Related Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties Transactions with ANSAC prior to January 1, 2023 were considered transactions with a related party. As discussed in Note 4 , on January 1, 2023, ANSAC became a wholly owned subsidiary of Genesis, and as such, the activity related to ANSAC is not included for the year ended December 31, 2023 in the table below. Transactions with related parties were as follows: Year Ended December 31, 2023 2022 2021 Revenues: Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (1) $ 18,713 $ 14,606 $ 13,846 Revenues from product sales to ANSAC — 418,232 280,935 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 (1) 9,124 1,057 965 Charges for services from ANSAC — 9,891 1,213 (1) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. Our CEO, Mr. Grant E. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. Grant E. 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 reflect what we would expect to obtain in an arms-length transaction. Transactions with Unconsolidated Affiliates Poseidon

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 (Increase) decrease in: Accounts receivable $ 159,426 $ (261,849) $ (75,165) Inventories (37,566) 2,087 20,370 Deferred charges 48,835 41,634 27,390 Other current assets (2,110) (6,971) (1,190) Increase (decrease) in: Accounts payable (135,289) 152,138 44,119 Accrued liabilities (29,122) (14,857) 14,520 Net changes in components of operating assets and liabilities $ 4,174 $ (87,818) $ 30,044 Payments of interest and commitment fees were $276.2 million, $236.9 million and $202.0 million during the years ended December 31, 2023, 2022 and 2021, respectively. We capitalized interest of $43.2 million, $18.1 million and $4.4 million during the years ended December 31, 2023, 2022 and 2021, respectively. During the years ended December 31, 2023, 2022 and 2021, we paid income taxes of $0.9 million, $1.0 million and $0.7 million, respectively. At December 31, 2023, 2022 and 2021, we had incurred liabilities for fixed and intangible asset additions totaling $172.7 million, $93.5 million and $51.7 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. The increase in this amount is principally due to the increase in capital expenditures associated with our Granger Optimization Project ( Note 1 2 ) and our offshore growth capital projects.

Equity-Based Compensation Plans

Equity-Based Compensation Plans	12 Months Ended
	Dec. 31, 2023
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. During 2023, we granted 74,106 phantom units with tandem DERs at a weighted average grant fair value of $10.26 per unit. During 2022, we granted 70,068 phantom units with tandem DERs at a weighted average grant date fair value of $9.92 per unit. During 2021, we granted 71,340 phantom units with tandem DERs at a weighted average grant date fair value of $8.83 per unit. The phantom units granted for 2023, 2022, and 2021 were made only to directors. Awards to management and other key employees during these periods were made under the 2018 LTIP plan and were not equity-based awards. A summary of our phantom unit activity for our service-based awards to our directors is set forth below: Service-Based Awards Number of Average Total Unvested at December 31, 2020 165,662 $ 11.19 $ 1,853 Granted 71,340 8.83 630 Settled (28,484) 9.05 (258) Unvested at December 31, 2021 208,518 10.67 2,225 Granted 70,068 9.92 695 Settled (58,454) 16.17 (945) Unvested at December 31, 2022 220,132 8.97 1,975 Granted 74,106 10.26 760 Settled (177,640) 7.46 (1,325) Unvested at December 31, 2023 116,598 $ 12.09 $ 1,410 We recorded compensation expense of $1.2 million, $0.7 million, and $1.4 million for the years ended December 31, 2023, 2022 and 2021, respectively, in “General and administrative expenses” on the Consolidated Statements of Operations. Our liability for these awards totaled $1.4 million and $2.1 million at December 31, 2023 and 2022, respectively, and is included within “Accrued liabilities” on the Consolidated Balance Sheets.

Major Customers and Credit Risk

Major Customers and Credit Risk	12 Months Ended
	Dec. 31, 2023
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 in this operation (as well as in our offshore pipeline transportation, marine transportation, and sulfur services businesses) 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 exchange-traded is limited due to daily margin requirements of the exchange. In our Alkali Business, we typically contract with similar customers year over year domestically and internationally and deliver our products to a variety of end markets. A change in supply and/or demand could adversely affect our operating results. 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 2022 and 2021 our largest customer was ANSAC, which accounted for 15% and 13%, respectively, of total consolidated revenues. No single customer exceeded 10% of total consolidated revenues during 2023. As discussed in Note 4 , on January 1, 2023, ANSAC became a wholly owned subsidiary of Genesis. Prior to January 1, 2023, a large portion of our soda ash production was sold to ANSAC and a disproportionate amount of our trade receivables and sales in our soda and sulfur services segment were related to ANSAC.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Crude Oil and Petroleum Products Hedges We have exposure to commodity price changes related to our petroleum inventory and purchase commitments. We utilize derivative instruments (exchange-traded futures, options and swap contracts) to hedge our exposure to crude oil, fuel oil and other 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. We recognize any changes in the fair value of our derivative contracts as increases or decreases in “Onshore facilities and transportation product costs” in the Consolidated Statements of Operations. 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 within “Onshore facilities and transportation product costs” in the Consolidated Statements of Operations. Natural Gas Hedges Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts, futures, and option contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts are used to 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 natural gas derivative contracts as increases or decreases within “Soda and sulfur services operating costs” in the Consolidated Statements of Operations. Forward Freight Hedges ANSAC is exposed to fluctuations in freight rates for vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge future freight rates for forecasted shipments. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of forward freight contracts as increases or decreases within “Soda and sulfur services operating costs” in the Consolidated Statements of Operations. Bunker Fuel Hedges ANSAC is exposed to fluctuations in the price of bunker fuel consumed by vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge bunker fuel prices for forecasted shipments. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of bunker fuel contracts as increases or decreases within “Soda and sulfur services operating costs” in the Consolidated Statements of Operations. Rail Fuel Surcharge Hedges ANSAC enters into rail transport agreements that require us to pay rail fuel surcharges based on changes in the U.S. On-Highway Diesel Fuel Price published by the U.S. Department of Energy (“DOE”). We use exchange-traded or over-the-counter futures, swaps and options to hedge fluctuations in the fuel price. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of bunker fuel contracts as increases or decreases within “Soda and sulfur services operating costs” in the Consolidated Statements of Operations. 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 Class A Convertible 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 our Class A Convertible Preferred Units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other expense, net” in our Consolidated Statement of Operations. On the election date, the holders of the Class A Convertible Preferred Units elected to reset the rate to 11.24%, the sum of the three-month LIBOR of 3.74% plus 750 basis points. The fair value of the embedded derivative at the time of election was a liability of $101.8 million. As of the election date, the feature within the Class A Convertible Preferred Units that required bifurcation no longer existed and we adjusted the carrying value of the Class A Convertible Preferred Units to include the fair value of the previously bifurcated amount at the election date. See Note 12 for additional information regarding our Class A Convertible Preferred Units and the Rate Reset Election. Balance Sheet Netting and Broker Margin Accounts 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 fair value amounts recorded for our exchange-traded derivative contracts against required margin funding in “Current Assets - Other” in our Consolidated Balance Sheets. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. Margin requirements are intended to mitigate a party’s exposure to market volatility and counterparty credit risk. On a daily basis, our account equity (consisting of the sum of our cash margin 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, 2023, we had a net broker receivable of approximately $10.9 million (consisting of initial margin of $5.7 million increased by $5.2 million of variation margin). As of December 31, 2022, we had a net broker receivable of approximately $4.0 million (consisting of initial margin of $3.8 million increased by $0.2 million of variation margin). At December 31, 2023 and December 31, 2022, 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. At December 31, 2023, we had the following outstanding derivative contracts that were entered into to economically hedge inventory, fixed price purchase commitments or forecasted purchases. Sell (Short) Buy (Long) Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 Bbls) 234 29 Weighted average contract price per Bbl $ 74.71 74.89 Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 Bbls) 8 1 Weighted average contract price per Bbl $ 74.89 $ 74.89 Natural gas swaps: Contract volumes (10,000 MMBtu) — 1,323 Weighted average price differential per MMBtu $ — $ 0.56 Natural gas futures: Contract volumes (10,000 MMBtu) 210 1,344 Weighted average contract price per MMBtu $ 2.54 $ 3.58 Natural gas options: Contract volumes (10,000 MMBtu) 6 3 Weighted average premium received/paid $ 0.75 $ 0.02 Bunker fuel futures: Contract volumes (metric tons "MT") — 62,000 Weighted average price per MT $ — $ 537.45 DOE diesel options: Contract volumes (1,000 Gal) — 2,750 Weighted average premium received/paid $ — $ 0.33 Financial Statement Impacts Unrealized gains are subtracted from net income (loss) and unrealized losses are added to net income (loss) 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 (loss) in determining cash flows from operating activities. Changes in the cash margin balance required to maintain our exchange-traded derivative contracts also affect cash flows from operating activities. 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 Consolidated Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivatives are recorded in “Current Assets - Other” (offset against margin deposits) and offsetting change in fair value of inventory is recorded Excess, if any, over effective portion of hedge is recorded in “Onshore facilities and transportation 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: Hedges consisting of crude oil, heating oil, fuel oil, bunker fuel, diesel fuel, petroleum products and natural gas futures, forward contracts, swaps and put and call options Volatility in crude oil, natural gas, bunker fuel, diesel fuel and petroleum products prices - effect on market value of inventory, fixed price purchase commitments or forecasted purchases Natural gas swap derivatives are recorded in “Current Assets - Accounts receivable - trade, net” or “Current liabilities - Accrued liabilities” Other derivatives are recorded in “Current Assets - Other” (offset against margin deposits) Entire amount of change in fair value of derivative is recorded in “Onshore facilities and transportation costs - product costs” and “Soda and sulfur services operating costs” Preferred Distribution Rate Reset Election This instrument is not related to a specific risk, but is a part of a host contract with the issuance of our Class A Convertible Preferred Units Derivative no longer existed as of December 31, 2022. Entire amount of change in fair value of derivative is recorded in “Other expense, net” The following tables reflect the estimated fair value position of our derivatives at December 31, 2023 and 2022: Fair Value of Derivative Assets and Liabilities Fair Value Consolidated December 31, 2023 December 31, 2022 Asset Derivatives: Natural Gas Swap (undesignated hedge) Current Assets - Accounts receivable - trade, net 3,710 36,844 Commodity derivatives—futures and put and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other (1) $ 1,235 $ 1,238 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) (1,235) (1,238) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures (designated hedges): Gross amount of recognized assets Current Assets - Other (1) $ 716 $ — Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) (716) — Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Liability Derivatives: Natural Gas Swap (undesignated hedge) Current Liabilities - Accrued Liabilities (5,536) (4,692) Commodity derivatives—futures and put and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (12,384) $ (11,061) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 12,384 5,217 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ (5,844) Commodity derivatives—futures (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (120) $ — Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 120 — Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — (1) As noted above, our exchange-traded derivatives are transacted through brokerage accounts and subject to margin requirements. We offset fair value amounts recorded for our exchange-traded derivative contracts against required margin deposits recorded in our Consolidated Balance Sheets under “Current Assets - Other”. Effect on Operating Results Amount of Gain (Loss) Recognized in Income (Loss) Year Ended Consolidated Statements of Operations Location 2023 2022 2021 Commodity derivatives—futures and options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ 617 $ 1,403 $ (7,634) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, soda and sulfur services operating costs (21,372) 6,013 (8,891) Total commodity derivatives $ (20,755) $ 7,416 $ (16,525) Natural gas swaps Soda and sulfur services operating costs 6,953 $ 31,904 $ 1,174 Preferred Distribution Rate Reset Election Other expense, net $ — $ (18,584) $ (30,838) We have no derivative contracts with credit contingent features.

Fair-Value Measurements

Fair-Value Measurements	12 Months Ended
	Dec. 31, 2021
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, 2023 and 2022. December 31, 2023 December 31, 2022 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 1,951 $ 3,710 $ — $ 1,238 $ 36,844 $ — Liabilities $ (12,504) $ (5,536) $ — $ (11,061) $ (4,692) $ — 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, 2020 $ (52,372) Net loss for the period including earnings (30,838) Balance as of December 31, 2021 (83,210) Net loss for the period including earnings (18,584) Reclassification to Mezzanine Equity 101,794 Balance as of December 31, 2022 $ — 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, 2023 and 2022. The fair value of the embedded derivative feature was based on a valuation model that estimates the fair value of the convertible preferred units with and without a Rate Reset Election. This model contained inputs, including our common unit price relative to the issuance price, the current dividend yield, the discount yield (which is adjusted periodically for changes associated with the industry’s credit markets), default probabilities, equity volatility, U.S. Treasury yields and timing estimates which involved management judgment. Our equity volatility rate used to value our embedded derivative feature was 50% at September 29, 2022, which represented the final valuation date of the embedded derivative due to the Rate Reset Election. Due primarily to the election of the rate reset increasing the distribution rate from 8.75% to 11.24%, we recorded an unrealized loss of $18.6 million for the year ended December 31, 2022. Due primarily to a decrease in our discount yield compared to December 31, 2020 as a result of significant fluctuations in the energy industry credit markets and volatility in our common unit price during the period, we recorded an unrealized loss of $30.8 million for the year ended December 31, 2021. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as “ Other expense, net. See Note 1 9 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. See Note 4 for more information regarding the assets and liabilities acquired during 2023. 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 senior secured 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, 2023 our senior unsecured notes had a carrying value of $3.1 billion and fair value of $3.2 billion, compared to a carrying value of $2.9 billion and fair value of $2.7 billion at December 31, 2022. 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. At December 31, 2023, our Alkali senior secured notes had a carrying value and fair value of $0.4 billion. The fair value of the Alkali senior secured notes is determined based on trade information in the financial market of securities with similar features and is considered a Level 2 fair value measurement.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans We sponsor a defined benefit pension plan for union-only employees of our Alkali Business. We account for the Alkali Business pension plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus, the related assets and liability costs of the plan are recorded in the Consolidated Balance Sheets. Under the Alkali Business pension plan, each eligible employee will automatically become a participant upon completion of one year of credited service. Retirement benefits under this plan are calculated based on the total years of service of an eligible participant, multiplied by a specified benefit rate in effect at the termination of the plan participant’s years of service. The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheets are as follows: December 31, 2023 2022 Change in benefit obligation: Benefit Obligation, beginning of year $ 42,065 $ 55,934 Service Cost 3,119 5,181 Interest Cost 2,205 1,804 Actuarial Gain (Loss) 1,358 (19,557) Benefits Paid (1,449) (1,297) Benefit Obligation, end of year 47,298 42,065 Change in plan assets: Fair Value of Plan Assets, beginning of year 30,073 35,288 Actual Return on Plan Assets 5,270 (6,363) Employer Contributions 3,100 2,445 Benefits Paid (1,449) (1,297) Fair Value of Plan assets, end of year 36,994 30,073 Funded Status at end of period $ (10,304) $ (11,992) Amounts recognized in the Consolidated Balance Sheets: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (10,304) (11,992) Net Liability at end of year $ (10,304) $ (11,992) Amounts recognized in accumulated other comprehensive income: Prior Service Cost 4,215 4,702 Net actuarial gain (12,196) (10,816) Amounts recognized in accumulated other comprehensive income: $ (7,981) $ (6,114) 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 2024 Contributions by Employer $ 4,488 Future Expected Benefit Payments 2024 $ 1,436 2025 1,750 2026 1,898 2027 2,072 2028 2,220 2029-2033 13,166 Net Periodic Pension Costs The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2023 2022 2021 Service Cost $ 3,119 $ 5,181 $ 6,020 Interest Cost 2,205 1,804 1,576 Expected Return on Assets (2,099) (1,959) (1,831) Amortization of Prior Service Cost 487 487 487 Actuarial Gain (434) — — Total Net Periodic Benefit Costs $ 3,278 $ 5,513 $ 6,252 Significant Assumptions Discount rates are determined annually and are based on rates of return of high-quality long-term fixed income securities currently available and expected to be available during the maturity of the pension benefits. The long-term rate of return estimation for the Alkali Business pension plan is based on a capital asset pricing model using historical data and a forecasted earnings model. An expected return on plan assets analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors. The Alkali Business pension plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan’s management. The committee is responsible for the oversight and management of the plan’s investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee’s investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company’s obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2023 December 31, 2022 Discount Rate 5.16 % 5.33 % Expected Long-term Rate of Return 6.69 % 6.71 % 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 5.33%. Pension Plan Assets We maintain target allocation percentages among various asset classes based on an investment policy established for the pension plan, which was last amended in November 2020. The target allocation is designed based on the strategic objectives, spending policy and risk tolerance of the plan. Pension plan asset allocations at December 31, 2023 by asset category are as follows: December 31, 2023 Target % Minimum Maximum Equity securities 67 % 58 % 76 % Fixed Income 20 % 11 % 29 % Alternative Investments 11 % 2 % 20 % Cash and Equivalents 2 % — % 7 % A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2023 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 5,212 $ — $ — $ 5,212 $ 4,592 $ — $ — $ 4,592 Equity securities 24,612 — — 24,612 20,838 — — 20,838 Fixed income and other securities 7,170 — — 7,170 4,643 — — 4,643 $ 36,994 $ — $ — $ 36,994 $ 30,073 $ — $ — $ 30,073

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments and Guarantees We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can be made that such environmental releases may not substantially affect our business. Other Matters Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations or cash flows.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
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. During 2023, we paid federal and state income taxes on these operations. Our income tax expense (benefit) is as follows: Year Ended December 31, 2023 2022 2021 Current: Federal $ 211 $ — $ — State 836 815 690 Total current income tax expense $ 1,047 $ 815 $ 690 Deferred: Federal $ 248 $ 1,814 $ 1,097 State (1,314) 540 (117) Total deferred income tax expense (benefit) $ (1,066) $ 2,354 $ 980 Total income tax expense (benefit) $ (19) $ 3,169 $ 1,670 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, 2023 2022 Deferred tax assets: Net operating loss carryforwards $ 13,631 $ 15,313 Right of use liabilities 36,148 — Other 4,823 2,333 Total long-term deferred tax asset 54,602 17,646 Valuation allowances (3,802) (3,471) Total deferred tax assets $ 50,800 $ 14,175 Deferred tax liabilities: Long-term: Fixed assets $ (2,408) $ (1,730) Intangible assets (29,635) (27,033) Right of use assets (36,150) — Other (117) (2,064) Total long-term liability (68,310) (30,827) Total deferred tax liabilities $ (68,310) $ (30,827) Total net deferred tax liability $ (17,510) $ (16,652) 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, 2023 2022 2021 Income (loss) from operations before income taxes $ 146,328 $ 132,304 $ (136,362) Partnership income (loss) not subject to federal income tax (135,349) (126,403) 140,092 Income subject to federal income taxes $ 10,979 $ 5,901 $ 3,730 Tax expense at federal statutory rate $ 2,306 $ 1,239 $ 783 State income taxes, net of federal tax (467) 1,248 574 Return to provision, federal and state (169) 44 (227) Other (2,077) (18) 112 Valuation allowance 388 656 428 Income tax expense (benefit) $ (19) $ 3,169 $ 1,670 Effective tax rate on income (loss) from operations before income taxes (0.01) % 2.4 % (1.2) % At December 31, 2023, 2022 and 2021, we had no uncertain tax positions.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022 and our results of operations, statements of comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2023, 2022 and 2021. 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. (“Poseidon”), a 29% interest in Odyssey Pipeline L.L.C. (“Odyssey”), a 26.8% interest in Paloma Pipeline Company (“Paloma”), and a 25.7% interest in Neptune Pipeline Company, LLC, (“Neptune”). We account for our investments in these joint ventures by the equity method of accounting. See Note 9 . Noncontrolling interests Noncontrolling interests represent any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our Consolidated Balance Sheets amounts shown as noncontrolling interests in equity. See Note 1 2 for additional discussion regarding our noncontrolling interests.
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, including the estimates of future asset retirement obligations, (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, (4) estimates of variable consideration for revenue recognition, (5) estimated fair value of derivative instruments, and (6) estimated useful lives of our fixed and intangible assets (including the reserve life of our mineral leaseholds) for the use in calculating depreciation, depletion, and amortization of long-lived assets and intangible assets. 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 periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. Restricted Cash
Accounts Receivable	Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and estimate an allowance for amounts that we expect will not be fully recovered. An allowance for credit losses is determined based upon historical collectability trends, recoveries, historical write-offs, and current market data for the partnership’s customers in order to estimate projected losses. 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. Within our Alkali Business, the cost of inventories are determined using the FIFO method, 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 25 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
Leases, lessee	Lease Accounting
Leases, lessor	Lease Accounting
Intangible and Other Assets	Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives on a straight-line basis. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented.
Goodwill	Goodwill
Environmental Liabilities	Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
Equity-Based Compensation	Equity-Based Compensation
Revenue Recognition	Revenue Recognition 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, we recognize revenue either over time as services are being performed or at a point in time for product sales. Fee-based Revenues We provide a variety of fee-based transportation and logistics services to our customers across several of our reportable segments as outlined below. Service contracts generally contain a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over the contract period, and therefore, qualify as a single performance obligation that is satisfied over time. The customer receives and consumes the benefit of our services simultaneously with the provision of those services. Offshore Pipeline Transportation Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of natural gas or per barrel of crude oil) gathered, transported, or processed for each volume delivered. Fees are based either on contractual arrangements or tariffs regulated by the FERC. Certain of our contracts include a single performance obligation to stand ready, on a monthly basis, to provide capacity on our assets. Revenue associated with these fee-based services is recognized as volumes are delivered over the performance obligation period. In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer regardless of the volume the customer actually delivers to the platform or through the pipeline. In addition to these offshore pipeline transportation revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, our performance obligation does not change throughout the life of the contract. Therefore revenue is recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously-recognized revenue will not occur throughout the life of the contract. These estimates are reassessed at each reporting period as required. Billings to our customers are reflected at the contract rate. Differences between the amounts we bill our customers and the revenue recognized on any one contract results in the recognition of 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, terminaling services and rail unloading services, among others, primarily on a per barrel fee basis. Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff. 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 measuring 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, we have a single performance obligation to transport and deliver the barrels. 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 Soda and Sulfur Services Product sales in our soda 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: 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 still 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 is 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 entire transaction price is allocated to the performance obligation. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. For certain sales of soda ash, we offer volume inventive credits, or rebates, to customers based on the quantity purchased within a period of time as determined by the contract. The volume inventive credit is not earned by the customer until the minimum quantity of soda ash is purchased. Our policy is to reduce the transaction price allocated to these performance obligations so that our revenue is presented net of the volume incentive credits we expect to be realized. 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: 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. The transaction price 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, the transaction price is known at the time of revenue recognition and invoicing. The entire transaction price is allocated to a single performance obligation. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations. Sulfur Services Our sulfur services business primarily provides sulfur removal 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 receive 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. 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, 2023. 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 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. The most significant operating costs in our soda and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS processing plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport and market the soda ash, other alkali products, NaHS and caustic soda. 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. 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, barges and other vessels, including personnel costs, fuel and maintenance of our equipment or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein.
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 We use derivative instruments to hedge exposure to commodity price and fuel and freight price risk. Derivative transactions, which can include exchange-traded futures and option contracts, and commodity price swap contracts 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. As of December 31, 2023, we did not have any cash flow hedges. In addition, we determined that a certain feature within our Class A Convertible Preferred Units represented an embedded derivative, which was required to be bifurcated and recorded at fair value, with changes in fair value in respective periods recorded in our Consolidated Statements of Operations. As of September 29, 2022, the feature was no longer required to be bifurcated and valued.
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 other comprehensive income (loss)
Business Acquisitions	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. The fair value of the assets acquired, liabilities assumed, or noncontrolling interest in the acquiree may be adjusted during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. Refer to Note 4
Recent and Proposed Accounting Pronouncements	Recent and Proposed Accounting Pronouncements In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” (“ASU 2023-09”), which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in ASU 2023-09 provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid information. ASU 2023-09 is effective prospectively to all annual periods beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact of this standard on our disclosures. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”), which enhances the disclosures required for operating segments in our annual and interim Consolidated Financial Statements. ASU 2023-07 is effective retrospectively for fiscal years beginning after December 15, 2023 and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact of this standard on our disclosures. All other new accounting pronouncements that have been issued, but not yet effective are currently being evaluated and at this time are not expected to have a material impact on our financial position or results of operations.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue Recognition [Abstract]
Schedule of Disaggregation of Revenue	The following tables reflects the disaggregation of our revenues by major category for the years ended December 31, 2023, December 31, 2022, and December 31, 2021, respectively: Year Ended December 31, 2023 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 382,154 $ — $ 327,464 $ 54,783 $ 764,401 Product Sales — 1,639,195 — 678,347 2,317,542 Sulfur Services — 95,053 — — 95,053 $ 382,154 $ 1,734,248 $ 327,464 $ 733,130 $ 3,176,996 Year Ended December 31, 2022 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 319,045 $ — $ 293,295 $ 68,625 $ 680,965 Product Sales — 1,152,450 — 859,907 2,012,357 Sulfur Services — 95,635 — — 95,635 $ 319,045 $ 1,248,085 $ 293,295 $ 928,532 $ 2,788,957 Year Ended December 31, 2021 Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated Fee-based revenues $ 278,459 $ — $ 190,827 $ 86,711 $ 555,997 Product Sales — 863,264 — 604,847 1,468,111 Sulfur Services — 101,368 — — 101,368 $ 278,459 $ 964,632 $ 190,827 $ 691,558 $ 2,125,476
Schedule of Contract Asset and Liabilities Balances Activity	The table below depicts our contract asset and liability balances at December 31, 2023 and December 31, 2022: Contract Assets Contract Liabilities Other Assets Accrued Liabilities Other Long-Term Liabilities Balance at December 31, 2022 $ — $ 2,087 $ 64,478 Balance at December 31, 2023 859 11,460 112,734
Schedule of Revenue Expected to be Recognized in Future Periods	The following chart depicts how we expect to recognize revenues for future periods related to these contracts: Offshore Pipeline Transportation Onshore Facilities and Transportation 2024 $ 119,185 $ 1,800 2025 136,326 — 2026 110,428 — 2027 66,828 — 2028 45,453 — Thereafter 124,184 — Total $ 602,404 $ 1,800

Business Consolidation (Tables)

Business Consolidation (Tables)	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Summary of Unaudited Consolidated Balance Sheet and Statements of Operations	The allocation of the purchase price, as presented within our Consolidated Balance Sheet as of December 31, 2023, is summarized as follows: Cash and cash equivalents $ 4,332 Accounts receivable - trade, net 231,797 Inventories 19,522 Other current assets 14,203 Fixed assets, at cost 4,000 Right of use assets, net 93,208 Intangible assets, net of amortization 14,992 Other Assets, net of amortization 400 Accounts payable - trade (1) (228,106) Accrued liabilities (75,224) Deferred tax liabilities (1,482) Other long-term liabilities (77,642) Net Assets $ — (1) Our Consolidated Statement of Operations include the results of ANSAC since January 1, 2023. The following table presents selected financial information included in our Consolidated Statement of Operations for the period presented: Year Ending Revenues $ 394,948 Net Income Attributable to Genesis Energy, L.P. 8,139 Year Ending December 31, 2023 2022 Pro forma consolidated financial operating results: Revenues $ 3,176,996 $ 3,246,477 Net Income Attributable to Genesis Energy, L.P. 117,720 75,457 Net Income (Loss) Attributable to Common Unitholders 26,995 (4,595) Basic and diluted earnings (loss) per common unit: As reported net income (loss) per common unit $ 0.22 $ (0.04) Pro forma net income (loss) per common unit $ 0.22 $ (0.04)

Lease Accounting (Tables)

Lease Accounting (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of Lease Balances by Major Categories	Refer to the table below for our lease balances as of December 31, 2023 and December 31, 2022. Leases Classification Financial Statement Caption December 31, December 31, 2022 Assets Transportation Equipment Right of Use Assets, net $ 115,689 $ 65,375 Office Space & Equipment Right of Use Assets, net 9,014 7,238 Facilities and Equipment Right of Use Assets, net 115,638 52,664 Total Right of Use Assets, net $ 240,341 $ 125,277 Liabilities Current Accrued liabilities 29,869 17,978 Non-Current Other long-term liabilities 214,946 113,844 Total Lease Liability $ 244,815 $ 131,822
Schedule of Maturity of Lease Liabilities	The following table presents the maturities of our operating lease liabilities as of December 31, 2023 on an undiscounted cash flow basis reconciled to the present value recorded on our Consolidated Balance Sheets: Maturity of Lease Liabilities Transportation Equipment Office Space and Equipment Facilities and Equipment Operating Leases 2024 $ 30,039 $ 2,355 $ 15,259 $ 47,653 2025 23,649 2,778 15,295 41,722 2026 16,550 2,453 15,347 34,350 2027 13,545 2,186 15,392 31,123 2028 10,023 1,805 15,438 27,266 Thereafter 82,215 9,585 151,204 243,004 Total Lease Payments 176,021 21,162 227,935 425,118 Less: Interest (64,394) (6,081) (109,828) (180,303) Present value of operating lease liabilities $ 111,627 $ 15,081 $ 118,107 $ 244,815
Schedule of Lease Term and Discount Rates	The following table presents the weighted average remaining terms and discount rates related to our right of use assets: Lease Term and Discount Rate December 31, 2023 December 31, 2022 Weighted-average remaining lease term 13.18 years 13.70 years Weighted-average discount rate 8.35% 7.75% The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases: Year Ended Cash Flows Information 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities $ 58,979 $ 28,576 $ 33,145 Leased assets obtained in exchange for new operating lease liabilities 150,917 9,443 8,296

Receivables (Tables)

Receivables (Tables)	12 Months Ended
	Dec. 31, 2023
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Schedule of Trade Accounts Receivables Net	Accounts receivable – trade, net consisted of the following: December 31, 2023 2022 Accounts receivable - trade $ 762,116 $ 724,419 Allowance for credit losses (2,569) (2,852) Accounts receivable - trade, net $ 759,547 $ 721,567
Schedule of Allowance For Credit Losses	The following table presents the activity of our allowance for credit losses for the periods indicated: December 31, 2023 2022 2021 Balance at beginning of period $ 2,852 $ 4,825 $ 6,258 Charges to (recoveries of) costs and expenses, net 1,666 172 (902) Amounts written off (1,949) (2,145) (531) Balance at end of period $ 2,569 $ 2,852 $ 4,825

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Schedule of Major Components of Inventories	The major components of inventories were as follows: December 31, 2023 2022 Petroleum products $ — $ 56 Crude oil 22,320 6,673 Caustic soda 9,150 15,258 NaHS 17,605 7,085 Raw materials - Alkali Business 8,355 5,819 Work-in-process - Alkali Business 11,404 9,599 Finished goods, net - Alkali Business 48,706 18,772 Materials and supplies, net - Alkali Business 17,691 14,881 Total $ 135,231 $ 78,143

Fixed Assets and Asset Retire_2

Fixed Assets and Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Fixed Assets And Asset Retirement Obligations [Abstract]
Schedule of Fixed Assets	Fixed assets consisted of the following: December 31, 2023 2022 Crude oil and natural gas pipelines and related assets $ 2,945,215 $ 2,844,288 Alkali facilities, machinery, and equipment 1,147,291 701,313 Onshore facilities, machinery, and equipment 271,271 269,949 Transportation equipment 24,913 22,340 Marine vessels 1,021,080 1,017,087 Land, buildings and improvements 293,733 231,651 Office equipment, furniture and fixtures 25,029 24,271 Construction in progress (1) 731,197 712,971 Other 41,168 41,168 Fixed assets, at cost 6,500,897 5,865,038 Less: Accumulated depreciation (1,972,596) (1,768,465) Net fixed assets $ 4,528,301 $ 4,096,573 (1)
Schedule of Mineral Leaseholds	Mineral Leaseholds Our Mineral Leaseholds, relating to our Alkali Business, consist of the following: December 31, 2023 December 31, 2022 Mineral leaseholds $ 566,019 $ 566,019 Less: Accumulated depletion (25,499) (20,897) Mineral leaseholds, net $ 540,520 $ 545,122
Schedule of Change in Asset Retirement Obligation	A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2020 $ 176,852 Accretion expense 10,038 Revisions in timing and estimated costs of AROs 35,735 Acquisitions 3,008 Settlements (4,727) December 31, 2021 $ 220,906 Accretion expense 13,092 Revisions in timing and estimated costs of AROs 11,216 Settlements (16,641) December 31, 2022 $ 228,573 Accretion expense 12,040 Revisions in timing and estimated costs of AROs 3,185 Settlements (90) December 31, 2023 $ 243,708

Equity Investees (Tables)

Equity Investees (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 Genesis’ share of operating earnings $ 80,461 $ 68,469 $ 73,389 Amortization of differences attributable to Genesis’ carrying value of equity investments (14,263) (14,263) (15,491) Net equity in earnings $ 66,198 $ 54,206 $ 57,898 Distributions earned (1) $ 90,833 $ 75,406 $ 84,106

Intangible Assets, Goodwill a_2

Intangible Assets, Goodwill and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	The following table reflects the components of intangible assets being amortized at December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Weighted Gross Accumulated Carrying Gross Accumulated Carrying Offshore pipeline contract intangibles 19 158,101 70,036 88,065 158,101 61,715 96,386 Other 10 70,974 17,502 53,472 45,191 14,257 30,934 Total $ 229,075 $ 87,538 $ 141,537 $ 203,292 $ 75,972 $ 127,320
Schedule of Estimated Amortization Expense	The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2024 2025 2026 2027 2028 Offshore pipeline contract intangibles $ 8,321 $ 8,321 $ 8,321 $ 8,321 $ 8,321 Other 6,504 6,244 5,932 5,485 5,235 Total $ 14,825 $ 14,565 $ 14,253 $ 13,806 $ 13,556
Schedule of Other Assets	Other assets consisted of the following: December 31, 2023 2022 Deferred marine charges, net (1) $ 19,651 $ 20,503 Unamortized debt issuance costs on senior secured credit facility 5,676 2,591 Other deferred charges, net 12,914 9,114 Other assets, net of amortization $ 38,241 $ 32,208 (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 ).

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Obligations Under Debt Arrangements	At December 31, 2023 and 2022, our obligations under debt arrangements consisted of the following: December 31, 2023 December 31, 2022 Principal Unamortized Premium, Discount and Debt Issuance Costs Net Value Principal Unamortized Premium and Debt Issuance Costs Net Value Senior secured credit facility-Revolving Loan (1) $ 298,300 $ — $ 298,300 $ 205,400 $ — $ 205,400 5.625% senior unsecured notes due 2024 — — — 341,135 1,249 339,886 6.500% senior unsecured notes due 2025 — — — 534,834 3,265 531,569 6.250% senior unsecured notes due 2026 339,310 1,746 337,564 339,310 2,481 336,829 8.000% senior unsecured notes due 2027 981,245 3,549 977,696 981,245 4,956 976,289 7.750% senior unsecured notes due 2028 679,360 6,121 673,239 679,360 7,621 671,739 8.250% senior unsecured notes due 2029 600,000 17,202 582,798 — — — 8.875% senior unsecured notes due 2030 500,000 8,342 491,658 — — — 5.875% Alkali senior secured notes due 2042 (2) 425,000 21,791 403,209 425,000 22,558 402,442 Total long-term debt $ 3,823,215 $ 58,751 $ 3,764,464 $ 3,506,284 $ 42,130 $ 3,464,154 (1) Unamortized debt issuance costs associated with our senior secured credit facility (included in “Other Assets, net of amortization” on the Consolidated Balance Sheets) were $5.7 million and $2.6 million as of December 31, 2023 and December 31, 2022, respectively.
Schedule of Summary of Applicable Redemption Periods	A summary of the applicable redemption periods is provided in the table below: 2026 Notes 2027 Notes 2028 Notes 2029 Notes 2030 Notes Redemption right beginning on February 15, 2021 January 15, 2024 February 1, 2023 January 15, 2026 April 15, 2026 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to N/A N/A N/A January 15, 2026 April 15, 2026 .

Partners' Capital, Mezzanine _2

Partners' Capital, Mezzanine Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Schedule of Paid Distributions	We paid the following cash distributions to common unitholders: Distribution For Date Paid Per Unit Amount Total Amount 2021 1 st Quarter May 14, 2021 $ 0.1500 $ 18,387 2 nd Quarter August 13, 2021 $ 0.1500 $ 18,387 3 rd Quarter November 12, 2021 $ 0.1500 $ 18,387 4 th Quarter February 14, 2022 $ 0.1500 $ 18,387 2022 1 st Quarter May 13, 2022 $ 0.1500 $ 18,387 2 nd Quarter August 12, 2022 $ 0.1500 $ 18,387 3 rd Quarter November 14, 2022 $ 0.1500 $ 18,387 4 th Quarter February 14, 2023 $ 0.1500 $ 18,387 2023 1 st Quarter May 15, 2023 $ 0.1500 $ 18,387 2 nd Quarter August 14, 2023 $ 0.1500 $ 18,387 3 rd Quarter November 14, 2023 $ 0.1500 $ 18,370 4 th Quarter February 14, 2024 $ 0.1500 $ 18,370 We paid the following cash distributions to our Class A Convertible Preferred unitholders: Distribution For Date Paid Per Unit Total 2021 1 st Quarter May 14, 2021 $ 0.7374 $ 18,684 2 nd Quarter August 13, 2021 $ 0.7374 $ 18,684 3 rd Quarter November 12, 2021 $ 0.7374 $ 18,684 4 th Quarter February 14, 2022 $ 0.7374 $ 18,684 2022 1 st Quarter May 13, 2022 $ 0.7374 $ 18,684 2 nd Quarter August 12, 2022 $ 0.7374 $ 18,684 3 rd Quarter November 14, 2022 $ 0.7374 $ 18,684 4 th Quarter February 14, 2023 $ 0.9473 $ 24,002 2023 1 st Quarter May 15, 2023 $ 0.9473 $ 24,002 2 nd Quarter August 14, 2023 $ 0.9473 $ 23,314 3 rd Quarter November 14, 2023 $ 0.9473 $ 22,612 4 th Quarter February 14, 2024 $ 0.9473 $ 21,894
Schedule of Changes in Redeemable Noncontrolling Interest	The following table shows the change in our redeemable noncontrolling interests from December 31, 2021 to December 31, 2022: Balance as of December 31, 2021 $ 259,568 Issuance of preferred units, net of issuance costs (1) 5,249 PIK distribution 9,993 Redemption accretion 1,908 Tax distributions (1) (6,631) Adjustment to Base Preferred Return Amount 18,542 Redemption of preferred units on May 17, 2022 (288,629) Balance as of December 31, 2022 — (1) We issued 5,356 Alkali Holdings preferred units to BXC to satisfy the Company’s obligation to pay tax distributions during 2022.

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2023
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): Year Ended 2023 2022 2021 Net income (loss) attributable to Genesis Energy L.P. $ 117,720 $ 75,457 $ (165,067) Less: Accumulated distributions attributable to Class A Convertible Preferred Units (90,725) (80,052) (74,736) Net income (loss) available to common unitholders $ 26,995 $ (4,595) $ (239,803) Weighted average outstanding units 122,535 122,579 122,579 Basic and diluted net income (loss) per common unit $ 0.22 $ (0.04) $ (1.96)

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information for each year presented below is as follows: Offshore Pipeline Transportation Soda and Sulfur Services Marine Transportation Onshore Facilities and Transportation Total Year Ended December 31, 2023 Segment Margin (1) $ 406,672 $ 282,014 $ 110,423 $ 27,953 $ 827,062 Capital expenditures (2) $ 410,237 $ 219,393 $ 42,681 $ 19,018 $ 691,329 Revenues: External customers $ 377,842 $ 1,743,327 $ 327,464 $ 728,363 $ 3,176,996 Intersegment (3) 4,312 (9,079) — 4,767 $ — Total revenues of reportable segments $ 382,154 $ 1,734,248 $ 327,464 $ 733,130 $ 3,176,996 Year Ended December 31, 2022 Segment Margin (1) $ 363,373 $ 306,718 $ 66,209 $ 33,755 $ 770,055 Capital expenditures (2) $ 241,446 $ 174,518 $ 39,084 $ 5,878 $ 460,926 Revenues: External customers $ 319,045 $ 1,258,236 $ 292,925 $ 918,751 $ 2,788,957 Intersegment (3) — (10,151) 370 9,781 $ — Total revenues of reportable segments $ 319,045 $ 1,248,085 $ 293,295 $ 928,532 $ 2,788,957 Year Ended December 31, 2021 Segment Margin (1) $ 317,560 $ 166,773 $ 34,572 $ 98,824 $ 617,729 Capital expenditures (2) $ 50,546 $ 227,118 $ 34,456 $ 4,609 $ 316,729 Revenues: External customers $ 278,459 $ 973,354 $ 188,011 $ 685,652 $ 2,125,476 Intersegment (3) — (8,722) 2,816 5,906 $ — Total revenues of reportable segments $ 278,459 $ 964,632 $ 190,827 $ 691,558 $ 2,125,476 (1) A reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin to for each year is presented below. (2) 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 contributions to equity investees, if any. (3) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions. Total assets by reportable segment were as follows: December 31, 2023 December 31, 2022 Offshore pipeline transportation $ 2,580,032 $ 2,290,488 Soda and sulfur services 2,705,350 2,358,086 Marine Transportation 645,020 681,231 Onshore facilities and transportation 1,019,113 981,354 Other assets 69,263 54,833 Total consolidated assets $ 7,018,778 $ 6,365,992
Schedule of Reconciliation of Segment Margin To (Loss) Income Before Income Taxes	Reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to total Segment Margin: Year Ended 2023 2022 2021 Net income (loss) attributable to Genesis Energy, L.P. $ 117,720 $ 75,457 $ (165,067) Corporate general and administrative expenses 73,876 71,820 61,287 Depreciation, depletion, amortization and accretion 291,731 307,519 315,896 Interest expense 244,663 226,156 233,724 Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income (1) 24,635 21,199 26,207 Other non-cash items (2) 13,488 (8,315) 30,907 Distributions from unrestricted subsidiaries not included in income (3) — 32,000 70,000 Cancellation of debt income ( Note 1 1 ) — (8,618) — Loss on extinguishment of debt (Note 1 1 ) 4,627 794 1,627 Differences in timing of cash receipts for certain contractual arrangements (4) 56,341 51,102 15,482 Gain on sale of asset, net to our ownership interest (Note 8 ) — (32,000) — Change in provision for leased items no longer in use — (671) 598 Income tax expense (benefit) (19) 3,169 1,670 Redeemable noncontrolling interest redemption value adjustments (5) — 30,443 25,398 Total Segment Margin $ 827,062 $ 770,055 $ 617,729 (1) Includes distributions attributable to the period and received during or promptly following such period. (2) 2023 includes unrealized losses of $36.7 million from the valuation of our commodity derivative transactions (excluding fair value hedges). 2022 includes unrealized gains of $24.4 million from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized losses of $18.6 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. 2021 includes unrealized gains of $0.1 million from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized losses of $30.8 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. (3) 2022 includes $32.0 million in cash receipts associated with the sale of the Independence Hub platform by our 80% owned unrestricted subsidiary (as defined under our credit agreement), Independence Hub, LLC. 2021 includes $70.0 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. (4) 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. (5) 2022 includes PIK distributions and accretion on the redemption feature of our Alkali Holdings preferred units, and valuation adjustments to the redemption feature as the associated Alkali Holdings preferred units were redeemed during the year ended December 31, 2022. 2021 includes PIK distributions and accretion on the redemption feature attributable to our Alkali Holdings preferred units. Refer to Note 1 2 for additional information.

Transactions with Related Par_2

Transactions with Related Parties (Tables)	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Schedule of Transactions With Related Parties	Transactions with related parties were as follows: Year Ended December 31, 2023 2022 2021 Revenues: Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (1) $ 18,713 $ 14,606 $ 13,846 Revenues from product sales to ANSAC — 418,232 280,935 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 (1) 9,124 1,057 965 Charges for services from ANSAC — 9,891 1,213 (1) We own a 64% interest in Poseidon Oil Pipeline Company, LLC.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 (Increase) decrease in: Accounts receivable $ 159,426 $ (261,849) $ (75,165) Inventories (37,566) 2,087 20,370 Deferred charges 48,835 41,634 27,390 Other current assets (2,110) (6,971) (1,190) Increase (decrease) in: Accounts payable (135,289) 152,138 44,119 Accrued liabilities (29,122) (14,857) 14,520 Net changes in components of operating assets and liabilities $ 4,174 $ (87,818) $ 30,044

Equity-Based Compensation Pla_2

Equity-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Schedule of Service-Based And Performance-Based Awards	A summary of our phantom unit activity for our service-based awards to our directors is set forth below: Service-Based Awards Number of Average Total Unvested at December 31, 2020 165,662 $ 11.19 $ 1,853 Granted 71,340 8.83 630 Settled (28,484) 9.05 (258) Unvested at December 31, 2021 208,518 10.67 2,225 Granted 70,068 9.92 695 Settled (58,454) 16.17 (945) Unvested at December 31, 2022 220,132 8.97 1,975 Granted 74,106 10.26 760 Settled (177,640) 7.46 (1,325) Unvested at December 31, 2023 116,598 $ 12.09 $ 1,410

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivatives Entered Into Hedge Inventory or Fixed Price Purchase Commitments	At December 31, 2023, we had the following outstanding derivative contracts that were entered into to economically hedge inventory, fixed price purchase commitments or forecasted purchases. Sell (Short) Buy (Long) Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 Bbls) 234 29 Weighted average contract price per Bbl $ 74.71 74.89 Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 Bbls) 8 1 Weighted average contract price per Bbl $ 74.89 $ 74.89 Natural gas swaps: Contract volumes (10,000 MMBtu) — 1,323 Weighted average price differential per MMBtu $ — $ 0.56 Natural gas futures: Contract volumes (10,000 MMBtu) 210 1,344 Weighted average contract price per MMBtu $ 2.54 $ 3.58 Natural gas options: Contract volumes (10,000 MMBtu) 6 3 Weighted average premium received/paid $ 0.75 $ 0.02 Bunker fuel futures: Contract volumes (metric tons "MT") — 62,000 Weighted average price per MT $ — $ 537.45 DOE diesel options: Contract volumes (1,000 Gal) — 2,750 Weighted average premium received/paid $ — $ 0.33
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 Consolidated Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivatives are recorded in “Current Assets - Other” (offset against margin deposits) and offsetting change in fair value of inventory is recorded Excess, if any, over effective portion of hedge is recorded in “Onshore facilities and transportation 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: Hedges consisting of crude oil, heating oil, fuel oil, bunker fuel, diesel fuel, petroleum products and natural gas futures, forward contracts, swaps and put and call options Volatility in crude oil, natural gas, bunker fuel, diesel fuel and petroleum products prices - effect on market value of inventory, fixed price purchase commitments or forecasted purchases Natural gas swap derivatives are recorded in “Current Assets - Accounts receivable - trade, net” or “Current liabilities - Accrued liabilities” Other derivatives are recorded in “Current Assets - Other” (offset against margin deposits) Entire amount of change in fair value of derivative is recorded in “Onshore facilities and transportation costs - product costs” and “Soda and sulfur services operating costs” Preferred Distribution Rate Reset Election This instrument is not related to a specific risk, but is a part of a host contract with the issuance of our Class A Convertible Preferred Units Derivative no longer existed as of December 31, 2022. Entire amount of change in fair value of derivative is recorded in “Other expense, net”
Schedule of Fair Value of Derivative Assets And Liabilities	The following tables reflect the estimated fair value position of our derivatives at December 31, 2023 and 2022: Fair Value of Derivative Assets and Liabilities Fair Value Consolidated December 31, 2023 December 31, 2022 Asset Derivatives: Natural Gas Swap (undesignated hedge) Current Assets - Accounts receivable - trade, net 3,710 36,844 Commodity derivatives—futures and put and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other (1) $ 1,235 $ 1,238 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) (1,235) (1,238) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures (designated hedges): Gross amount of recognized assets Current Assets - Other (1) $ 716 $ — Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) (716) — Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Liability Derivatives: Natural Gas Swap (undesignated hedge) Current Liabilities - Accrued Liabilities (5,536) (4,692) Commodity derivatives—futures and put and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (12,384) $ (11,061) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 12,384 5,217 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ (5,844) Commodity derivatives—futures (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (120) $ — Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 120 — Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — (1) As noted above, our exchange-traded derivatives are transacted through brokerage accounts and subject to margin requirements. We offset fair value amounts recorded for our exchange-traded derivative contracts against required margin deposits recorded in our Consolidated Balance Sheets under “Current Assets - Other”.
Schedule of Effect on Consolidated Statements of Operations And Other Comprehensive Income (Loss)	Effect on Operating Results Amount of Gain (Loss) Recognized in Income (Loss) Year Ended Consolidated Statements of Operations Location 2023 2022 2021 Commodity derivatives—futures and options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ 617 $ 1,403 $ (7,634) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs, soda and sulfur services operating costs (21,372) 6,013 (8,891) Total commodity derivatives $ (20,755) $ 7,416 $ (16,525) Natural gas swaps Soda and sulfur services operating costs 6,953 $ 31,904 $ 1,174 Preferred Distribution Rate Reset Election Other expense, net $ — $ (18,584) $ (30,838)

Fair-Value Measurements (Tables

Fair-Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022. December 31, 2023 December 31, 2022 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 1,951 $ 3,710 $ — $ 1,238 $ 36,844 $ — Liabilities $ (12,504) $ (5,536) $ — $ (11,061) $ (4,692) $ —
Schedule of Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	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, 2020 $ (52,372) Net loss for the period including earnings (30,838) Balance as of December 31, 2021 (83,210) Net loss for the period including earnings (18,584) Reclassification to Mezzanine Equity 101,794 Balance as of December 31, 2022 $ —

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2023
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 Sheets are as follows: December 31, 2023 2022 Change in benefit obligation: Benefit Obligation, beginning of year $ 42,065 $ 55,934 Service Cost 3,119 5,181 Interest Cost 2,205 1,804 Actuarial Gain (Loss) 1,358 (19,557) Benefits Paid (1,449) (1,297) Benefit Obligation, end of year 47,298 42,065 Change in plan assets: Fair Value of Plan Assets, beginning of year 30,073 35,288 Actual Return on Plan Assets 5,270 (6,363) Employer Contributions 3,100 2,445 Benefits Paid (1,449) (1,297) Fair Value of Plan assets, end of year 36,994 30,073 Funded Status at end of period $ (10,304) $ (11,992) Amounts recognized in the Consolidated Balance Sheets: Non-current assets $ — $ — Current liabilities — — Non-current Liabilities (10,304) (11,992) Net Liability at end of year $ (10,304) $ (11,992) Amounts recognized in accumulated other comprehensive income: Prior Service Cost 4,215 4,702 Net actuarial gain (12,196) (10,816) Amounts recognized in accumulated other comprehensive income: $ (7,981) $ (6,114)
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 2024 Contributions by Employer $ 4,488 Future Expected Benefit Payments 2024 $ 1,436 2025 1,750 2026 1,898 2027 2,072 2028 2,220 2029-2033 13,166
Schedule of Components of Net Periodic Costs	The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2023 2022 2021 Service Cost $ 3,119 $ 5,181 $ 6,020 Interest Cost 2,205 1,804 1,576 Expected Return on Assets (2,099) (1,959) (1,831) Amortization of Prior Service Cost 487 487 487 Actuarial Gain (434) — — Total Net Periodic Benefit Costs $ 3,278 $ 5,513 $ 6,252
Schedule of Weighted Average Assumptions Used To Determine Benefit Obligation	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, 2023 December 31, 2022 Discount Rate 5.16 % 5.33 % Expected Long-term Rate of Return 6.69 % 6.71 % 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 5.33%.
Schedule of Pension Plan Assets Allocations	Pension plan asset allocations at December 31, 2023 by asset category are as follows: December 31, 2023 Target % Minimum Maximum Equity securities 67 % 58 % 76 % Fixed Income 20 % 11 % 29 % Alternative Investments 11 % 2 % 20 % Cash and Equivalents 2 % — % 7 %
Schedule of Pension Plan Assets Measured at Fair Value	A summary of total investments for our pension plan assets measured at fair value is presented as of December 31 for the periods below: 2023 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 5,212 $ — $ — $ 5,212 $ 4,592 $ — $ — $ 4,592 Equity securities 24,612 — — 24,612 20,838 — — 20,838 Fixed income and other securities 7,170 — — 7,170 4,643 — — 4,643 $ 36,994 $ — $ — $ 36,994 $ 30,073 $ — $ — $ 30,073

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Income Tax (Benefit) Expense	Our income tax expense (benefit) is as follows: Year Ended December 31, 2023 2022 2021 Current: Federal $ 211 $ — $ — State 836 815 690 Total current income tax expense $ 1,047 $ 815 $ 690 Deferred: Federal $ 248 $ 1,814 $ 1,097 State (1,314) 540 (117) Total deferred income tax expense (benefit) $ (1,066) $ 2,354 $ 980 Total income tax expense (benefit) $ (19) $ 3,169 $ 1,670
Schedule of Deferred Tax Assets And Liabilities	Deferred tax assets and liabilities consist of the following: December 31, 2023 2022 Deferred tax assets: Net operating loss carryforwards $ 13,631 $ 15,313 Right of use liabilities 36,148 — Other 4,823 2,333 Total long-term deferred tax asset 54,602 17,646 Valuation allowances (3,802) (3,471) Total deferred tax assets $ 50,800 $ 14,175 Deferred tax liabilities: Long-term: Fixed assets $ (2,408) $ (1,730) Intangible assets (29,635) (27,033) Right of use assets (36,150) — Other (117) (2,064) Total long-term liability (68,310) (30,827) Total deferred tax liabilities $ (68,310) $ (30,827) Total net deferred tax liability $ (17,510) $ (16,652)
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, 2023 2022 2021 Income (loss) from operations before income taxes $ 146,328 $ 132,304 $ (136,362) Partnership income (loss) not subject to federal income tax (135,349) (126,403) 140,092 Income subject to federal income taxes $ 10,979 $ 5,901 $ 3,730 Tax expense at federal statutory rate $ 2,306 $ 1,239 $ 783 State income taxes, net of federal tax (467) 1,248 574 Return to provision, federal and state (169) 44 (227) Other (2,077) (18) 112 Valuation allowance 388 656 428 Income tax expense (benefit) $ (19) $ 3,169 $ 1,670 Effective tax rate on income (loss) from operations before income taxes (0.01) % 2.4 % (1.2) %

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2023 segment
Other Ownership Interests [Line Items]
Number of divisions that constitute reportable segments	4
Genesis Energy, LLC
Other Ownership Interests [Line Items]
Limited liability company, ownership interest owned	100%

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets	$ 0	$ 0	$ 0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax
Crude oil and natural gas pipelines and related assets | Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	5 years
Crude oil and natural gas pipelines and related assets | Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	40 years
Marine vessels | Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	20 years
Marine vessels | Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Onshore facilities, machinery, and equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Onshore facilities, machinery, and equipment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Transportation equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Transportation equipment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	7 years
Building and improvements | Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Building and improvements | Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	25 years
Poseidon Oil Pipeline Company
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	64%
Poseidon Oil Pipeline Company | Offshore pipeline transportation
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	64%
Neptune Pipeline Company LLC | Offshore pipeline transportation
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	25.70%
Neptune Pipeline Company LLC | Paloma Pipeline Company
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	26.80%
Odyssey Pipeline L.L.C. | Offshore pipeline transportation
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	29%

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregated Revenue) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Total revenues	$ 3,176,996	$ 2,788,957	$ 2,125,476
Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues	764,401	680,965	555,997
Product Sales
Disaggregation of Revenue [Line Items]
Total revenues	2,317,542	2,012,357	1,468,111
Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	95,053	95,635	101,368
Offshore Pipeline Transportation
Disaggregation of Revenue [Line Items]
Total revenues	382,154	319,045	278,459
Offshore Pipeline Transportation | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues	382,154	319,045	278,459
Offshore Pipeline Transportation | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues	0	0	0
Offshore Pipeline Transportation | Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	0	0	0
Soda and Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	1,734,248	1,248,085	964,632
Soda and Sulfur Services | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues	0	0	0
Soda and Sulfur Services | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues	1,639,195	1,152,450	863,264
Soda and Sulfur Services | Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	95,053	95,635	101,368
Marine Transportation
Disaggregation of Revenue [Line Items]
Total revenues	327,464	293,295	190,827
Marine Transportation | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues	327,464	293,295	190,827
Marine Transportation | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues	0	0	0
Marine Transportation | Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	0	0	0
Onshore Facilities and Transportation
Disaggregation of Revenue [Line Items]
Total revenues	733,130	928,532	691,558
Onshore Facilities and Transportation | Fee-based revenues
Disaggregation of Revenue [Line Items]
Total revenues	54,783	68,625	86,711
Onshore Facilities and Transportation | Product Sales
Disaggregation of Revenue [Line Items]
Total revenues	678,347	859,907	604,847
Onshore Facilities and Transportation | Sulfur Services
Disaggregation of Revenue [Line Items]
Total revenues	$ 0	$ 0	$ 0

Revenue Recognition (Contract A

Revenue Recognition (Contract Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Revenue Recognition [Abstract]
Contract Liabilities, Current	$ 11,460	$ 2,087
Contract Liabilities, Non-Current	112,734	64,478
Long-term contract assets	$ 859	$ 0

Revenue Recognition (Narrative)

Revenue Recognition (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Balances previously classified as contract liabilities in prior periods that were recognized as revenues	$ 2.6	$ 2.6	$ 3
Deferred revenue	$ 11.5
Revenue recognized as result of contract modification			$ 4.1

Revenue Recognition (Revenue Ex

Revenue Recognition (Revenue Expected to be Recognized in Future Periods) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability, Revenue Recognized	$ 2,600	$ 2,600	$ 3,000
Revenue recognized as result of contract modification			$ 4,100
Long-term contract assets	859	$ 0
Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	602,404
Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	1,800
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 119,185
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 1,800
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 136,326
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 110,428
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 66,828
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 45,453
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Offshore Pipeline Transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 124,184
Revenue expected timing of satisfaction period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Onshore facilities and transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized in future periods	$ 0
Revenue expected timing of satisfaction period

Business Consolidation - Narrat

Business Consolidation - Narrative (Details)	Jan. 01, 2023
Leaseholds and Leasehold Improvements
Asset Acquisition, Contingent Consideration [Line Items]
Acquired fixed assets, useful life	10 years
American Natural Soda Ash Corp. (ANSAC)
Asset Acquisition, Contingent Consideration [Line Items]
Voting interests acquired	100%

Business Consolidation - Unaudi

Business Consolidation - Unaudited Consolidated Balance Sheet and Statements of Operations (Details) - American Natural Soda Ash Corp. (ANSAC) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Jan. 01, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Cash and cash equivalents		$ 4,332
Accounts receivable - trade, net		231,797
Inventories		19,522
Other current assets		14,203
Fixed assets, at cost		4,000
Right of use assets, net		93,208
Intangible assets, net of amortization		14,992
Other Assets, net of amortization		400
Accounts payable, trade		(228,106)
Accrued liabilities		(75,224)
Deferred tax liabilities		(1,482)
Other long-term liabilities		(77,642)
Net Assets		$ 0
Revenues	$ 394,948
Net Income Attributable to Genesis Energy, L.P.	$ 8,139
Consolidation, Eliminations [Member]
Business Acquisition [Line Items]
Accounts receivable - trade, net			$ 133,400

Business Consolidation - Schedu

Business Consolidation - Schedule of Pro Forma Financial Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pro forma consolidated financial operating results:
Revenues	$ 3,176,996,000	$ 3,246,477,000
Net Income Attributable to Genesis Energy, L.P.	117,720,000	75,457,000
Net Loss Attributable to Common Unitholders, Basic (in dollars per unit)	26,995,000	(4,595,000)
Net Loss Attributable to Common Unitholders, Diluted (in dollars per unit)	$ 26,995,000	$ (4,595,000)
Basic and diluted earnings (loss) per common unit:
Basic Net Loss per Common Unit (in dollars per unit)	$ 0.22	$ (0.04)	$ (1.96)
Dilutive Net Income (Loss) per Common Unit (in dollars per unit)	0.22	(0.04)	$ (1.96)
Pro Forma net loss per common unit, basic (in dollars per unit)	0.22	(0.04)
Pro Forma net loss per common unit, diluted (in dollars per unit)	$ 0.22	$ (0.04)

Lease Accounting (Lease Balance

Lease Accounting (Lease Balances by Major Categories) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Operating Leased Assets [Line Items]
Total Right of Use Assets, net	$ 240,341	$ 125,277
Accrued liabilities, current	29,869	17,978
Other long-term liabilities, non-current	214,946	113,844
Present value of operating lease liabilities	$ 244,815	$ 131,822
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued liabilities	Accrued liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES
Transportation equipment
Operating Leased Assets [Line Items]
Total Right of Use Assets, net	$ 115,689	$ 65,375
Present value of operating lease liabilities	111,627
Office Space and Equipment
Operating Leased Assets [Line Items]
Total Right of Use Assets, net	9,014	7,238
Present value of operating lease liabilities	15,081
Facilities and Equipment
Operating Leased Assets [Line Items]
Total Right of Use Assets, net	115,638	$ 52,664
Present value of operating lease liabilities	$ 118,107

Lease Accounting (Narrative) (D

Lease Accounting (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease costs	$ 41,400	$ 13,600	$ 18,400
Mileage credits	22,500	22,400	20,800
Acquired fixed assets, useful life	$ 0	$ (671)	$ (598)
Direct finance lease receivable				$ 70,000

Lease Accounting (Maturity of L

Lease Accounting (Maturity of Lease Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Operating Leased Assets [Line Items]
2024	$ 47,653
2025	41,722
2026	34,350
2027	31,123
2028	27,266
Thereafter	243,004
Total Lease Payments	425,118
Less: Interest	(180,303)
Present value of operating lease liabilities	244,815	$ 131,822
Transportation equipment
Operating Leased Assets [Line Items]
2024	30,039
2025	23,649
2026	16,550
2027	13,545
2028	10,023
Thereafter	82,215
Total Lease Payments	176,021
Less: Interest	(64,394)
Present value of operating lease liabilities	111,627
Office Space and Equipment
Operating Leased Assets [Line Items]
2024	2,355
2025	2,778
2026	2,453
2027	2,186
2028	1,805
Thereafter	9,585
Total Lease Payments	21,162
Less: Interest	(6,081)
Present value of operating lease liabilities	15,081
Facilities and Equipment
Operating Leased Assets [Line Items]
2024	15,259
2025	15,295
2026	15,347
2027	15,392
2028	15,438
Thereafter	151,204
Total Lease Payments	227,935
Less: Interest	(109,828)
Present value of operating lease liabilities	$ 118,107

Lease Accounting (Lease Term an

Lease Accounting (Lease Term and Discount Rate) (Details)	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Weighted-average remaining lease term	13 years 2 months 4 days	13 years 8 months 12 days
Weighted-average discount rate	8.35%	7.75%

Lease Accounting (Cash Flow Inf

Lease Accounting (Cash Flow Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 58,979	$ 28,576	$ 33,145
Leased assets obtained in exchange for new operating lease liabilities	$ 150,917	$ 9,443	$ 8,296

Lease Accounting (Operating Lea

Lease Accounting (Operating Lease Income) (Details) - Marine transportation - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessor, Lease, Description [Line Items]
Lease revenue	$ 23,600	$ 16,400	$ 15,000
Expected undiscounted cash flows, year one	28,100
Expected undiscounted cash flows, year two	29,600
Expected undiscounted cash flows, year three	30,700
Expected undiscounted cash flows, year four	$ 15,200

Receivables (Schedule of Trade

Receivables (Schedule of Trade Accounts Receivables Net) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Accounts receivable - trade	$ 762,116	$ 724,419
Allowance for credit losses	(2,569)	(2,852)	$ (4,825)	$ (6,258)
Accounts receivable - trade, net	$ 759,547	$ 721,567

Receivables (Schedule of Allowa

Receivables (Schedule of Allowance for Credit Losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	$ 2,852	$ 4,825	$ 6,258
Charges to (recoveries of) costs and expenses, net	1,666	172	(902)
Amounts written off	(1,949)	(2,145)	(531)
Balance at end of period	$ 2,569	$ 2,852	$ 4,825

Inventories (Details)

Inventories (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Petroleum products	$ 0	$ 56,000
Crude oil	22,320,000	6,673,000
Caustic soda	9,150,000	15,258,000
NaHS	17,605,000	7,085,000
Raw materials - Alkali Business	8,355,000	5,819,000
Work-in-process - Alkali Business	11,404,000	9,599,000
Finished goods, net - Alkali Business	48,706,000	18,772,000
Materials and supplies, net - Alkali Business	17,691,000	14,881,000
Inventories	135,231,000	78,143,000
Inventory write down	$ 200,000	$ 2,900,000

Fixed Assets and Asset Retire_3

Fixed Assets and Asset Retirement Obligations (Schedule of Fixed Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 6,500,897	$ 5,865,038
Less: Accumulated depreciation	(1,972,596)	(1,768,465)
Net fixed assets	4,528,301	4,096,573
Crude oil and natural gas pipelines and related assets
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	2,945,215	2,844,288
Onshore facilities, machinery, and equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	271,271	269,949
Onshore facilities, machinery, and equipment | Alkali Business
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	1,147,291	701,313
Transportation equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	24,913	22,340
Marine vessels
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	1,021,080	1,017,087
Land, buildings and improvements
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	293,733	231,651
Office equipment, furniture and fixtures
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	25,029	24,271
Construction in progress(1)
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	731,197	712,971
Other
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 41,168	$ 41,168

Fixed Assets and Asset Retire_4

Fixed Assets and Asset Retirement Obligations (Schedule of Mineral Leaseholds) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Mineral leaseholds	$ 566,019	$ 566,019
Less: Accumulated depletion	(25,499)	(20,897)
Mineral leaseholds, net	$ 540,520	$ 545,122

Fixed Assets and Asset Retire_5

Fixed Assets and Asset Retirement Obligations (Narrative) (Details) - USD ($)		12 Months Ended
	Apr. 29, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligations Details [Line Items]
Depreciation expense		$ 263,500,000	$ 281,400,000	$ 295,400,000
Depletion expense		4,600,000	3,900,000	3,600,000
Payments to noncontrolling interests		44,579,000	31,867,000	903,000
Asset retirement obligation		243,708,000	228,573,000	$ 220,906,000	$ 176,852,000
Noncontrolling Interest | Independence Hub, LLC
Asset Retirement Obligations Details [Line Items]
Payments to noncontrolling interests	$ 8,000,000	$ 8,000,000
Noncontrolling Interest | Independence Hub, LLC | Genesis Energy, LLC
Asset Retirement Obligations Details [Line Items]
Noncontrolling interest percentage	20%	20%
Current Liabilities - Accrued Liabilities
Asset Retirement Obligations Details [Line Items]
Asset retirement obligation		$ 26,100,000	$ 26,600,000
Independence Hub, LLC | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Asset Retirement Obligations Details [Line Items]
Proceeds from Sale of Productive Assets	$ 40,000,000	$ 40,000,000

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 228,573	$ 220,906	$ 176,852
Accretion expense	12,040	13,092	10,038
Revisions in timing and estimated costs of AROs	3,185	11,216	35,735
Acquisitions			3,008
Settlements	(90)	(16,641)	(4,727)
Asset retirement obligations, ending balance	$ 243,708	$ 228,573	$ 220,906

Equity Investees (Narrative) (D

Equity Investees (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Unamortized excess cost amount	$ 291.4	$ 305.6

Equity Investees (Consolidated

Equity Investees (Consolidated Financial Statements Related to Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Genesis’ share of operating earnings	$ 80,461	$ 68,469	$ 73,389
Amortization of differences attributable to Genesis’ carrying value of equity investments	(14,263)	(14,263)	(15,491)
Net equity in earnings	66,198	54,206	57,898
Distributions earned(1)	$ 90,833	$ 75,406	$ 84,106

Intangible Assets, Goodwill a_3

Intangible Assets, Goodwill and Other Assets (Schedule of Intangible Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 229,075	$ 203,292
Accumulated Amortization	87,538	75,972
Carrying Value	$ 141,537	127,320
Other
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	10 years
Gross Carrying Amount	$ 70,974	45,191
Accumulated Amortization	17,502	14,257
Carrying Value	$ 53,472	30,934
Offshore pipeline transportation | Offshore pipeline contract intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	19 years
Gross Carrying Amount	$ 158,101	158,101
Accumulated Amortization	70,036	61,715
Carrying Value	$ 88,065	$ 96,386

Intangible Assets, Goodwill a_4

Intangible Assets, Goodwill and Other Assets (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Amortization of expense of intangible assets	$ 11,600	$ 10,300	$ 10,300
Goodwill	301,959	301,959
Impairment of goodwill	0	0	$ 0
Soda and sulfur services
Finite-Lived Intangible Assets [Line Items]
Goodwill	$ 301,900	$ 301,900

Intangible Assets, Goodwill a_5

Intangible Assets, Goodwill and Other Assets (Schedule of Estimated Amortization Expense) (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Finite-Lived Intangible Assets [Line Items]
2024	$ 14,825
2025	14,565
2026	14,253
2027	13,806
2028	13,556
Offshore pipeline contract intangibles
Finite-Lived Intangible Assets [Line Items]
2025	8,321
2026	8,321
2027	8,321
2028	8,321
Other
Finite-Lived Intangible Assets [Line Items]
2024	6,504
2025	6,244
2026	5,932
2027	5,485
2028	5,235
Offshore pipeline transportation | Offshore pipeline contract intangibles
Finite-Lived Intangible Assets [Line Items]
2024	$ 8,321

Intangible Assets, Goodwill a_6

Intangible Assets, Goodwill and Other Assets (Schedule of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Deferred marine charges, net	$ 19,651	$ 20,503
Unamortized debt issuance costs on senior secured credit facility	5,676	2,591
Other deferred charges, net	12,914	9,114
OTHER ASSETS, net of amortization	$ 38,241	$ 32,208

Debt (Schedule of Obligations U

Debt (Schedule of Obligations Under Debt Arrangements) (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	May 17, 2022	Dec. 17, 2020	Jan. 16, 2020	Dec. 11, 2017	May 15, 2014
Debt Instrument [Line Items]
Principal	$ 3,823,215,000	$ 3,506,284,000
Unamortized Premium, Discount and Debt Issuance Costs	58,751,000	42,130,000
Net Value	3,764,464,000	3,464,154,000
Senior Secured Credit Facility | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Principal	298,300,000	205,400,000
Unamortized Premium, Discount and Debt Issuance Costs	0	0
Net Value	$ 298,300,000	205,400,000
5.625% senior unsecured notes due 2024 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	5.625%						5.625%
Principal	$ 0	341,135,000
Unamortized Premium, Discount and Debt Issuance Costs	0	1,249,000
Net Value	$ 0	339,886,000
6.500% senior unsecured notes due 2025 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	6.50%
Principal	$ 0	534,834,000
Unamortized Premium, Discount and Debt Issuance Costs	0	3,265,000
Net Value	$ 0	531,569,000
6.250% senior unsecured notes due 2026 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	6.25%					6.25%
Principal	$ 339,310,000	339,310,000
Unamortized Premium, Discount and Debt Issuance Costs	1,746,000	2,481,000
Net Value	$ 337,564,000	336,829,000
8.000% senior unsecured notes due 2027 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	8%			8%
Principal	$ 981,245,000	981,245,000
Unamortized Premium, Discount and Debt Issuance Costs	3,549,000	4,956,000
Net Value	$ 977,696,000	976,289,000
7.750% senior unsecured notes due 2028 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	7.75%				7.75%
Principal	$ 679,360,000	679,360,000
Unamortized Premium, Discount and Debt Issuance Costs	6,121,000	7,621,000
Net Value	$ 673,239,000	671,739,000
8.250% senior unsecured notes due 2029 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	8.25%
Principal	$ 600,000,000	0
Unamortized Premium, Discount and Debt Issuance Costs	17,202,000	0
Net Value	$ 582,798,000	0
8.875% senior unsecured notes due 2030 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	8.875%
Principal	$ 500,000,000	0
Unamortized Premium, Discount and Debt Issuance Costs	8,342,000	0
Net Value	491,658,000	0
5.875% Alkali senior secured notes due 2042
Debt Instrument [Line Items]
Principal	$ 400,000,000
5.875% Alkali senior secured notes due 2042 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate	5.875%		5.875%
Principal	$ 425,000,000	425,000,000
Unamortized Premium, Discount and Debt Issuance Costs	21,791,000	22,558,000
Net Value	403,209,000	402,442,000
Revolving Loan | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Unamortized debt issuance costs included in other long term assets	$ 5,700,000	$ 2,600,000

Debt (Senior Secured Credit Fac

Debt (Senior Secured Credit Facility) (Details)

12 Months Ended

Sep. 30, 2023

Feb. 17, 2023 USD ($) extension

May 17, 2022 USD ($)

Nov. 17, 2021 USD ($)

Nov. 16, 2021

Dec. 31, 2023 USD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2028 USD ($)

Dec. 31, 2027 USD ($)

Dec. 31, 2026 USD ($)

Dec. 31, 2025 USD ($)

Dec. 31, 2024 USD ($)

Debt Instrument [Line Items]

Cash proceeds from the sale of a noncontrolling interest in a subsidiary

$ 0

$ 0

$ 418,140,000

Repayments of senior secured credit facility

1,090,666,000

815,100,000

1,371,000,000

Loss on debt extinguishment

(4,627,000)

(794,000)

$ 1,627,000

Principal

3,823,215,000

3,506,284,000

Restricted cash

$ 18,804,000

18,637,000

Affiliated Entity | CHOPS

Debt Instrument [Line Items]

Percentage of ownership in equity interest sold

0.36

Cash proceeds from the sale of a noncontrolling interest in a subsidiary

$ 418,000,000

Senior Secured Credit Facility | Line of Credit

Debt Instrument [Line Items]

Line of credit, unused capacity commitment fee percentage

0.50%

Credit facility aggregate accordion feature

$ 200,000,000

Extension period

1 year

Number of extensions | extension

2

Senior Secured Credit Facility | Line of Credit | Maximum

Debt Instrument [Line Items]

Line of credit, unused capacity commitment fee percentage

0.50%

Senior Secured Credit Facility | Line of Credit | Minimum

Debt Instrument [Line Items]

Line of credit, unused capacity commitment fee percentage

0.30%

Senior Secured Credit Facility | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Letter of credit, fee percentage

2.75%

Principal

$ 298,300,000

205,400,000

Senior Secured Credit Facility | Letter of Credit | Eurodollar Rate | Maximum

Debt Instrument [Line Items]

Letter of credit, fee percentage

3.50%

Senior Secured Credit Facility | Letter of Credit | Eurodollar Rate | Minimum

Debt Instrument [Line Items]

Letter of credit, fee percentage

2.25%

Revolving Loan | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 850,000,000

Senior secured credit facility, amount outstanding

$ 298,300,000

Letters of credit, outstanding amount

4,500,000

Total amount available for borrowings, remaining borrowing capacity

547,200,000

Revolving Loan | Line of Credit | Revolving Credit Facility | Petroleum Products

Debt Instrument [Line Items]

Senior secured credit facility, amount outstanding

19,300,000

Revolving Loan | Line of Credit | Revolving Credit Facility | Maximum

Debt Instrument [Line Items]

Letters of credit, outstanding amount

$ 100,000,000

Revolving Loan | Line of Credit | Revolving Credit Facility | Federal Funds Effective Rate

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

0.50%

Revolving Loan | Line of Credit | Revolving Credit Facility | LIBOR Rate | Maximum

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

1%

Revolving Loan | Line of Credit | Revolving Credit Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum | Term SOFR Adjustment

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

0.10%

Revolving Loan | Line of Credit | Revolving Credit Facility | Eurodollar Rate

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

275%

Revolving Loan | Line of Credit | Revolving Credit Facility | Eurodollar Rate | Maximum

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

350%

Revolving Loan | Line of Credit | Revolving Credit Facility | Eurodollar Rate | Minimum

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

2.25%

Revolving Loan | Line of Credit | Revolving Credit Facility | Alternate Base Rate

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

1.75%

Revolving Loan | Line of Credit | Revolving Credit Facility | Alternate Base Rate | Maximum

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

250%

Revolving Loan | Line of Credit | Revolving Credit Facility | Alternate Base Rate | Minimum

Debt Instrument [Line Items]

Debt instrument, basis spread on variable rate

1.25%

5.875% Alkali senior secured notes due 2042

Debt Instrument [Line Items]

Principal

$ 400,000,000

5.875% Alkali senior secured notes due 2042 | Senior Unsecured Notes

Debt Instrument [Line Items]

Principal

$ 425,000,000

$ 425,000,000

Debt interest rate

5.875%

5.875%

Limited term interest

0.10

Restricted cash

$ 18,800,000

Proceeds from issuance of debt, net of discount

$ 408,000,000

Issuance discount

$ 17,000,000

5.875% Alkali senior secured notes due 2042 | Senior Unsecured Notes | Scenario, Forecast

Debt Instrument [Line Items]

Principal repayments

$ 15,700,000

$ 14,600,000

$ 14,200,000

$ 13,100,000

$ 11,600,000

Debt (Senior Unsecured Notes) (

Debt (Senior Unsecured Notes) (Details) - USD ($)										12 Months Ended
	Dec. 08, 2023	Dec. 07, 2023	Jan. 26, 2023	Jan. 25, 2023	Jan. 24, 2023	Apr. 22, 2021	Dec. 17, 2020	Jan. 16, 2020	Dec. 11, 2017	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Aug. 14, 2017	May 15, 2014
Debt Instrument [Line Items]
Repayments of Unsecured Debt										$ 875,969,000	$ 72,241,000	$ 80,859,000
Loss on debt extinguishment										(4,627,000)	(794,000)	1,627,000
Unamortized Premium, Discount and Debt Issuance Costs										58,751,000	42,130,000
Cancellation of debt income										0	8,618,000	$ 0
Senior Unsecured Notes
Debt Instrument [Line Items]
Repayments of Unsecured Debt										$ 80,900,000
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to										35%
Cancellation of debt income										$ 8,600,000
Senior Unsecured Notes | Guarantor Subsidiaries | Genesis Energy, LLC | Genesis Finance Corporation
Debt Instrument [Line Items]
Aggregate principal amount of guaranteed debt										$ 3,100,000,000
Percentage of equity interest										100%
5.625% senior unsecured notes due 2024 | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal														$ 350,000,000
Debt interest rate										5.625%				5.625%
Repayments of Unsecured Debt			$ 25,000,000		$ 316,000,000
Loss on debt extinguishment			$ 1,800,000
Unamortized Premium, Discount and Debt Issuance Costs										$ 0	1,249,000
2030 Notes | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal				$ 500,000,000	$ 500,000,000
Debt interest rate				8.875%
Proceeds from issuance of debt, net of discount				$ 491,000,000
6.500% senior unsecured notes due 2025 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate										6.50%
Repayments of Unsecured Debt	$ 21,000,000	$ 514,000,000
Loss on debt extinguishment	$ 2,800,000
Unamortized Premium, Discount and Debt Issuance Costs										$ 0	3,265,000
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to										35%
6.500% senior unsecured notes due 2025 | Senior Unsecured Notes | Alkali Business
Debt Instrument [Line Items]
Senior unsecured notes, principal													$ 550,000,000
Debt interest rate													6.50%
6.250% senior unsecured notes due 2026 | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal									$ 450,000,000
Debt interest rate									6.25%	6.25%
Proceeds from issuance of debt, net of discount									$ 442,000,000
Unamortized Premium, Discount and Debt Issuance Costs										$ 1,746,000	2,481,000
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to										35%
2021 Notes | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate									5.75%
Repayments of Unsecured Debt									$ 205,000,000
7.750% senior unsecured notes due 2028 | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal								$ 750,000,000
Debt interest rate								7.75%		7.75%
Proceeds from issuance of debt, net of discount								$ 737,000,000
Unamortized Premium, Discount and Debt Issuance Costs										$ 6,121,000	7,621,000
6.750% senior unsecured notes due 2022 | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate								6.75%
Debt tendered and repaid								$ 555,000,000
8.000% senior unsecured notes due 2027 | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal						$ 250,000,000	$ 750,000,000
Debt interest rate							8%			8%
Proceeds from issuance of debt, net of discount							$ 737,000,000
Debt premium percentage						103.75%
Unamortized Premium, Discount and Debt Issuance Costs										$ 3,549,000	$ 4,956,000
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to										35%
Six Percentage Senior Unsecured Notes [Member] | Senior Unsecured Notes
Debt Instrument [Line Items]
Debt interest rate							6%
Repayments of Unsecured Debt							$ 317,000,000
2029 Notes | Senior Unsecured Notes
Debt Instrument [Line Items]
Senior unsecured notes, principal		$ 600,000,000
Debt interest rate		8.25%
Proceeds from issuance of debt, net of discount		$ 583,000,000
Unamortized Premium, Discount and Debt Issuance Costs		6,200,000
Senior Unsecured Notes | 5.625% senior unsecured notes due 2024
Debt Instrument [Line Items]
Senior unsecured notes, principal				25,000,000
Repayments of Long-term Debt				$ 316,000,000
Senior Unsecured Notes | 6.500% senior unsecured notes due 2025
Debt Instrument [Line Items]
Senior unsecured notes, principal		535,000,000
Repayments of Unsecured Debt		21,000,000
Repayments of Long-term Debt		$ 514,000,000

Debt (Redemption Periods Senior

Debt (Redemption Periods Senior Unsecured Notes) (Details) - Senior Unsecured Notes	12 Months Ended
	Dec. 31, 2023
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%
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%
2027 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%
2028 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%
2029 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%

Debt (Covenants and Compliance)

Debt (Covenants and Compliance) (Details) $ in Thousands	Dec. 07, 2023 USD ($)	Jan. 25, 2023 USD ($)	Dec. 31, 2023 metric
Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Number of primary financial metrics | metric			3
Consolidated senior secured leverage ratio			2.50
Consolidated interest coverage ratio			2.50
Line of Credit | Senior Secured Credit Facility | Thereafter
Debt Instrument [Line Items]
Consolidated leverage ratio			5.50
5.625% senior unsecured notes due 2024 | Senior Unsecured Notes
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 316,000
6.500% senior unsecured notes due 2025 | Senior Unsecured Notes
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 514,000

Partners' Capital, Mezzanine _3

Partners' Capital, Mezzanine Equity and Distributions (Additional Information) (Details) - shares		12 Months Ended
	Sep. 23, 2019	Dec. 31, 2023	Dec. 31, 2022
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		122,464,318	122,579,218
Cash or stock available for distributions, percent usually distributed		100%
Days to distribute		45 days
Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member]
Partners Capital And Distributions [Line Items]
Redeemable Noncontrolling Interest, Equity, Preferred, Period For Triggering Event To Occur	6 years 6 months
Class A | Partners’ Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		122,424,321
Class B | Partners’ Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in units)		39,997
Class A Convertible Preferred Units
Partners Capital And Distributions [Line Items]
Convertible preferred units outstanding (in units)		23,111,918	25,336,778

Partners' Capital, Mezzanine _4

Partners' Capital, Mezzanine Equity and Distributions (Distributions Paid) (Details) - USD ($)

12 Months Ended

Feb. 14, 2024

Nov. 14, 2023

Aug. 14, 2023

Jul. 03, 2023

May 15, 2023

Apr. 03, 2023

Feb. 14, 2023

Nov. 14, 2022

Aug. 12, 2022

May 13, 2022

Feb. 14, 2022

Nov. 12, 2021

Aug. 13, 2021

May 14, 2021

Dec. 31, 2023

Dec. 31, 2022

Class A Convertible Preferred Stock Units

Distribution Made to Limited Partner [Line Items]

Convertible preferred units outstanding (in units)

23,111,918

25,336,778

Temporary Equity, Stock Issued During Period, Shares, New Issues

2,224,860

2,224,860

(93,900,000)

Common Unitholders

Distribution Made to Limited Partner [Line Items]

Date Paid

Nov. 14, 2023

Aug. 14, 2023

May 15, 2023

Feb. 14, 2023

Nov. 14, 2022

Aug. 12, 2022

May 13, 2022

Feb. 14, 2022

Nov. 12, 2021

Aug. 13, 2021

May 14, 2021

Per Unit Amount (in dollars per unit)

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

$ 0.1500

Total Amount

$ 18,370,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

$ 18,387,000

Common Unitholders | Subsequent Event

Distribution Made to Limited Partner [Line Items]

Date Paid

Feb. 14, 2024

Per Unit Amount (in dollars per unit)

$ 0.1500

Total Amount

$ 18,370,000

Partners' Capital, Mezzanine _5

Partners' Capital, Mezzanine Equity and Distributions (Class A Convertible Preferred Units - Narrative) (Details) $ / shares in Units, $ in Thousands							3 Months Ended	12 Months Ended
	Sep. 01, 2024 USD ($) director shares	Jul. 03, 2023 $ / shares shares	Apr. 03, 2023 $ / shares shares	Sep. 01, 2022	Mar. 01, 2019 quarters	Sep. 01, 2017 USD ($) buyer $ / shares shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	Nov. 14, 2023 $ / shares	Aug. 14, 2023 $ / shares	Aug. 08, 2023 shares	May 15, 2023 $ / shares	Feb. 14, 2023 $ / shares	Nov. 14, 2022 $ / shares	Sep. 29, 2022	Aug. 12, 2022 $ / shares	May 16, 2022 shares	May 13, 2022 $ / shares	Feb. 14, 2022 $ / shares	Nov. 12, 2021 $ / shares	Aug. 13, 2021 $ / shares	May 14, 2021 $ / shares	Apr. 14, 2020 shares	Sep. 23, 2019 shares	Sep. 01, 2019 USD ($)
Temporary Equity [Line Items]
Stock Repurchased and Retired During Period, Value | $								$ 1,044
Maximum | Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member]
Temporary Equity [Line Items]
Convertible preferred units outstanding (in units)																									351,750	350,000
Class A Convertible Preferred Stock Units
Temporary Equity [Line Items]
Class A convertible preferred units issued (in units)							23,111,918	23,111,918	25,336,778
Number of shares authorized to be converted (in units)						7,416,498
Consecutive period for shares to be converted						12 months
Minimum number of shares outstanding authorized to be converted (in units)						592,768
Volume weighted average price percentage						95%
Consecutive trading days in period ending on fifth trading day						30 days
Consideration payable to holders in cash for change of control percentage						90%
Threshold trading days to notify holders				30 days		30 days
Change in control multiplier price percentage						101%
Temporary Equity, Basis Spread on Variable Rate					0.0200
Reset rate				10.75%			11.24%	11.24%									11.24%
Percentage below issue price				110%
Convertible preferred units outstanding (in units)							23,111,918	23,111,918	25,336,778
Accumulated distributions attributable to Class A preferred unitholders | $								$ (90,700)	$ (80,100)	$ (74,700)
Aggregate amount of conversion required, minimum | $																											$ 50,000
Number of quarters in trading period | quarters					2
Temporary Equity, Par or Stated Value Per Share | $ / shares		$ 35.2	$ 35.2
Temporary Equity, Stock Issued During Period, Shares, New Issues		2,224,860	2,224,860					(93,900,000)
Temporary Equity, Accretion to Redemption Value, Adjustment | $								$ 3,200
Class A Convertible Preferred Stock Units | Preferred Unitholders
Temporary Equity [Line Items]
Cash distributions per common unit (in dollars per unit) | $ / shares							$ 0.9473	$ 0.9473			$ 0.9473	$ 0.9473		$ 0.9473	$ 0.9473	$ 0.7374		$ 0.7374		$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374
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
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
Class A Convertible Preferred Stock Units | LIBOR Rate
Temporary Equity [Line Items]
Temporary Equity, Basis Spread on Variable Rate				0.0750													750
Reset rate																	3.74%
Class A Convertible Preferred Stock Units | Scenario, Forecast
Temporary Equity [Line Items]
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%
Aggregate number of ownership units required for initial purchasers to appoint directors (in units)	11,124,747
Number of directors that initial purchasers have right to appoint | director	2
Class A Convertible Preferred Stock Units | Minimum
Temporary Equity [Line Items]
Redemption premium percentage						115%
Reset rate																	8.75%
Class A Convertible Preferred Stock Units | Maximum
Temporary Equity [Line Items]
Redemption premium percentage						101%
Reset rate							11.24%	11.24%
Class A Convertible Preferred Stock Units | Private Placement
Temporary Equity [Line Items]
Private placement of convertible preferred units | $						$ 750,000
Class A convertible preferred units issued (in units)						22,249,494
Cash purchase price per unit (in dollars per unit) | $ / shares						$ 33.71
Number of initial purchasers | buyer						2
Class A | 2023 Repurchase Program
Temporary Equity [Line Items]
Stock Repurchased and Retired During Period, Value | $							$ 1,000
Stock Repurchase Program, Number of Shares Authorized to be Repurchased													12,253,922
Redeemable Non Controlling Interest | Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member]
Temporary Equity [Line Items]
Convertible preferred units outstanding (in units)							0	0											251,750							55,000

Partners' Capital, Mezzanine _6

Partners' Capital, Mezzanine Equity and Distributions (Preferred Cash Distributions Paid) (Details) - USD ($)	Feb. 14, 2024	Nov. 14, 2023	Aug. 14, 2023	May 15, 2023	Feb. 14, 2023	Nov. 14, 2022	Aug. 12, 2022	May 13, 2022	Feb. 14, 2022	Nov. 12, 2021	Aug. 13, 2021	May 14, 2021	Dec. 31, 2023
Common Unitholders
Partners Capital And Distributions [Line Items]
Date Paid		Nov. 14, 2023	Aug. 14, 2023	May 15, 2023	Feb. 14, 2023	Nov. 14, 2022	Aug. 12, 2022	May 13, 2022	Feb. 14, 2022	Nov. 12, 2021	Aug. 13, 2021	May 14, 2021
Cash distributions per common unit (in dollars per unit)		$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500	$ 0.1500
Total Amount		$ 18,370,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000	$ 18,387,000
Common Unitholders | Subsequent Event
Partners Capital And Distributions [Line Items]
Date Paid	Feb. 14, 2024
Cash distributions per common unit (in dollars per unit)	$ 0.1500
Total Amount	$ 18,370,000
Preferred Unitholders | Class A Convertible Preferred Stock Units
Partners Capital And Distributions [Line Items]
Cash distributions per common unit (in dollars per unit)		$ 0.9473	$ 0.9473	$ 0.9473	$ 0.9473	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.7374	$ 0.9473
Total Amount		$ 22,612,000	$ 23,314,000	$ 24,002,000	$ 24,002,000	$ 18,684,000	$ 18,684,000	$ 18,684,000	$ 18,684,000	$ 18,684,000	$ 18,684,000	$ 18,684,000
Preferred Unitholders | Class A Convertible Preferred Stock Units | Subsequent Event
Partners Capital And Distributions [Line Items]
Cash distributions per common unit (in dollars per unit)	$ 0.9473
Total Amount	$ 21,894,000

Partners' Capital, Mezzanine _7

Partners' Capital, Mezzanine Equity and Distributions (Redeemable Noncontrolling Interest- Narrative) (Details) - USD ($)			3 Months Ended	12 Months Ended
	Apr. 14, 2020	Sep. 23, 2019	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jul. 03, 2023	Apr. 03, 2023	May 17, 2022	May 16, 2022
Temporary Equity [Line Items]
Redeemable noncontrolling interest issued (in shares)			5,356	5,356
Redeemable noncontrolling interests, no preferred units issued and outstanding at December 31, 2023 and 0 preferred units issued and outstanding at December 31, 2022			$ 0	$ 0	$ 259,568,000				$ 288,629,000	$ 270,100,000
Redeemable noncontrolling interest redemption value adjustment				0	$ 30,443,000	$ 25,398,000
PIK distribution				9,993,000
Redemption accretion				1,908,000
Stock Repurchased and Retired During Period, Value				$ 1,044,000
Class A | 2023 Repurchase Program
Temporary Equity [Line Items]
Stock Repurchased and Retired During Period, Value			$ 1,000,000
Class A Convertible Preferred Stock Units
Temporary Equity [Line Items]
Convertible preferred units outstanding (in units)			23,111,918	23,111,918	25,336,778
Temporary Equity, Redemption Price Per Share							$ 33.71	$ 33.71
Temporary Equity, Accretion to Redemption Value, Adjustment				$ 3,200,000
Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member]
Temporary Equity [Line Items]
Preferred units, value		$ 55,000,000		18,500,000
Redeemable Noncontrolling Interest, Equity, Preferred, Commitment Period	4 years	3 years
Redeemable Noncontrolling Interest, Project Extension Period	1 year
Redeemable noncontrolling interest issued (in shares)	1,750
Redeemable Noncontrolling Interest, Equity, Preferred, Purchase Price Per Unit		$ 1,000
Redeemable Noncontrolling Interest, Equity, Preferred, Fair Value										$ 288,600,000
Redeemable noncontrolling interest redemption value adjustment				0	$ 30,443,000	25,398,000
PIK distribution				10,000,000		21,300,000
Redemption accretion				$ 1,900,000		$ 4,100,000
Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member] | Maximum
Temporary Equity [Line Items]
Convertible preferred units outstanding (in units)	351,750	350,000
Redeemable Noncontrolling Interest, Equity, Preferred, Amount Authorized		$ 350,000,000			$ 351,800,000
Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member] | Minimum
Temporary Equity [Line Items]
Redeemable Noncontrolling Interest, Equity, Preferred, Amount Authorized		$ 251,800,000
Subsidiaries [Member] | Genesis Alkali Holdings Company, LLC [Member] | Redeemable Non Controlling Interest
Temporary Equity [Line Items]
Convertible preferred units outstanding (in units)		55,000	0	0						251,750

Partners' Capital, Mezzanine _8

Partners' Capital, Mezzanine Equity and Distributions (Changes in Redeemable Noncontrolling Interests) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Jul. 03, 2023	Apr. 03, 2023	Dec. 31, 2022	May 17, 2022	May 16, 2022
Redeemable Noncontrolling Interest, Equity [Roll Forward]
Issuance of preferred units, net of issuance costs		$ 5,249
PIK distribution		9,993
Redemption accretion		1,908
Tax distributions		(6,631)
Adjustment to Base Preferred Return Amount		18,542
Redeemable Noncontrolling Interest, Equity, Preferred, Carrying Amount	$ 0	$ 0			$ (259,568)	$ (288,629)	$ (270,100)
Redeemable noncontrolling interest issued (in shares)	5,356	5,356
Class A Convertible Preferred Stock Units
Partners Capital And Distributions [Line Items]
Temporary Equity, Par or Stated Value Per Share			$ 35.2	$ 35.2
Temporary Equity, Accretion to Redemption Value, Adjustment		$ 3,200
2023 Repurchase Program | Class A
Partners Capital And Distributions [Line Items]
Stock Repurchased and Retired During Period, Shares	114,900

Partners' Capital, Mezzanine _9

Partners' Capital, Mezzanine Equity and Distributions (Noncontrolling Interest) (Details)					1 Months Ended	3 Months Ended	12 Months Ended
	Jul. 03, 2023 shares	Apr. 03, 2023 shares	Nov. 17, 2021 USD ($)	Nov. 16, 2021	Dec. 31, 2021	Dec. 31, 2023 $ / shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Aug. 08, 2023 shares
Subsidiary, Sale of Stock [Line Items]
Cash proceeds from the sale of a noncontrolling interest in a subsidiary							$ 0	$ 0	$ 418,140,000
Payments to noncontrolling interests							$ 44,579,000	$ 31,867,000	$ 903,000
Class A Convertible Preferred Stock Units
Subsidiary, Sale of Stock [Line Items]
Temporary Equity, Stock Issued During Period, Shares, New Issues | shares	2,224,860	2,224,860					(93,900,000)
2023 Repurchase Program | Class A
Subsidiary, Sale of Stock [Line Items]
Shares Acquired, Average Cost Per Share | $ / shares						$ 9.09
Stock Repurchase Program, Number of Shares Authorized to be Repurchased | shares										12,253,922
Stock Repurchase Program, Percentage of Shares Authorized to be Repurchased										0.10
Affiliated Entity | CHOPS
Subsidiary, Sale of Stock [Line Items]
Percentage of ownership in equity interest sold				0.36
Cash proceeds from the sale of a noncontrolling interest in a subsidiary			$ 418,000,000
Percentage of ownership in equity interest retained					64%
Affiliated Entity | Independence Hub, LLC | Genesis Energy, LLC
Subsidiary, Sale of Stock [Line Items]
Percentage of ownership equity interest						80%	80%

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share Reconciliation [Abstract]
Net income (loss) attributable to Genesis Energy L.P.	$ 117,720	$ 75,457	$ (165,067)
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(90,725)	(80,052)	(74,736)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS-BASIC	26,995	(4,595)	(239,803)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS-DILUTED	$ 26,995	$ (4,595)	$ (239,803)
Basic Weighted Average Outstanding Units (in units)	122,535	122,579	122,579
Dilutive Weighted Average Outstanding Units (in units)	122,535	122,579	122,579
Basic Net Loss per Common Unit (in dollars per unit)	$ 0.22	$ (0.04)	$ (1.96)
Dilutive Net Income (Loss) per Common Unit (in dollars per unit)	$ 0.22	$ (0.04)	$ (1.96)

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Segment Reporting [Abstract]
Number of divisions that constitute reportable segments | segment	4
Segment Reporting Information [Line Items]
Acquired fixed assets, useful life	$ 0	$ (671,000)	$ (598,000)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other expense, net	Other expense, net
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Independence Hub, LLC
Segment Reporting Information [Line Items]
Distributions from unrestricted subsidiaries not included in income		$ 32

Business Segment Information (S

Business Segment Information (Schedule of Revenues by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Total Segment Margin	$ 827,062	$ 770,055	$ 617,729
Total revenues	3,176,996	2,788,957	2,125,476
Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Total revenues	382,154	319,045	278,459
Soda and Sulfur Services
Segment Reporting Information [Line Items]
Total revenues	1,734,248	1,248,085	964,632
Marine Transportation
Segment Reporting Information [Line Items]
Total revenues	327,464	293,295	190,827
Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Total revenues	733,130	928,532	691,558
Operating Segments
Segment Reporting Information [Line Items]
Total Segment Margin	827,062	770,055	617,729
Capital Expenditures	691,329	460,926	316,729
Total revenues	3,176,996	2,788,957	2,125,476
Operating Segments | Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	406,672	363,373	317,560
Capital Expenditures	410,237	241,446	50,546
Total revenues	377,842	319,045	278,459
Operating Segments | Soda and Sulfur Services
Segment Reporting Information [Line Items]
Total Segment Margin	282,014	306,718	166,773
Capital Expenditures	219,393	174,518	227,118
Total revenues	1,743,327	1,258,236	973,354
Operating Segments | Marine Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	110,423	66,209	34,572
Capital Expenditures	42,681	39,084	34,456
Total revenues	327,464	292,925	188,011
Operating Segments | Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	27,953	33,755	98,824
Capital Expenditures	19,018	5,878	4,609
Total revenues	728,363	918,751	685,652
Intersegment
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Intersegment | Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Total revenues	4,312	0	0
Intersegment | Soda and Sulfur Services
Segment Reporting Information [Line Items]
Total revenues	(9,079)	(10,151)	(8,722)
Intersegment | Marine Transportation
Segment Reporting Information [Line Items]
Total revenues	0	370	2,816
Intersegment | Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Total revenues	$ 4,767	$ 9,781	$ 5,906

Business Segment Information _2

Business Segment Information (Schedule of Total Assets by Reportable Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 7,018,778	$ 6,365,992
Genesis Energy, LLC | Affiliated Entity | Independence Hub, LLC
Segment Reporting Information [Line Items]
Percentage of ownership equity interest	80%
Operating Segments | Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 2,580,032	2,290,488
Operating Segments | Soda and Sulfur Services
Segment Reporting Information [Line Items]
TOTAL ASSETS	2,705,350	2,358,086
Operating Segments | Marine Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	645,020	681,231
Operating Segments | Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,019,113	981,354
Other assets
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 69,263	$ 54,833

Business Segment Information (R

Business Segment Information (Reconciliation of Segment Margin to Net Income) (Details) - USD ($)		12 Months Ended
	Apr. 29, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting [Abstract]
Net income (loss) attributable to Genesis Energy L.P.		$ 117,720,000	$ 75,457,000	$ (165,067,000)
Corporate general and administrative expenses		73,876,000	71,820,000	61,287,000
Interest expense		244,663,000	226,156,000	233,724,000
Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income(1)		(24,635,000)	(21,199,000)	26,207,000
Other non-cash items		(13,488,000)	8,315,000	30,907,000
Cancellation of debt income		0	(8,618,000)	0
Loss on debt extinguishment		(4,627,000)	(794,000)	1,627,000
Income tax benefit (expense)		(19,000)	3,169,000	1,670,000
Redeemable noncontrolling interest redemption value adjustment		0	30,443,000	25,398,000
Total Segment Margin		827,062,000	770,055,000	617,729,000
Segment Reporting Information [Line Items]
Net loss for the period including earnings			(18,584,000)
Unrealized gain (loss) on derivatives		(36,635,000)	5,823,000	(30,700,000)
Depreciation, Depletion, Amortization And Accretion		291,731,000	307,519,000	(315,896,000)
Distribution from unrestricted subsidiaries not included in income		0	32,000,000	(70,000,000)
Differences In Timing Of Cash Receipts For Certain Contractual Arrangements		56,341,000	51,102,000	15,482,000
Write Off Of Amortization Of Leased Assets, Sublease Income And Other Adjustments		0	671,000	598,000
Gain (Loss) on Disposition of Assets, Net to Our Ownership Interest		0	(32,000,000)	0
Embedded Derivative Financial Instruments
Segment Reporting Information [Line Items]
Net loss for the period including earnings				(30,838,000)
Level 3 | Embedded Derivative Financial Instruments
Segment Reporting Information [Line Items]
Net loss for the period including earnings		$ 0	(18,584,000)	(30,838,000)
Genesis Energy, LLC | Affiliated Entity | Independence Hub, LLC
Segment Reporting Information [Line Items]
Percentage of ownership equity interest		80%
Genesis NEJD Pipeline, LLC
Segment Reporting [Abstract]
Distributions from unrestricted subsidiaries not included in income			70,000,000
Segment Reporting Information [Line Items]
Distributions from unrestricted subsidiaries not included in income			70,000,000
Embedded Derivative Financial Instruments
Segment Reporting Information [Line Items]
Net loss for the period including earnings				(30,800,000)
Unrealized gain (loss) on derivatives			(18,600,000)	(30,800,000)
Commodity Derivatives
Segment Reporting Information [Line Items]
Net loss for the period including earnings		$ (20,755,000)	7,416,000	(16,525,000)
Unrealized gain (loss) on derivatives		36,700,000	(24,400,000)	$ (100,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Independence Hub, LLC
Segment Reporting [Abstract]
Distributions from unrestricted subsidiaries not included in income			32
Segment Reporting Information [Line Items]
Distributions from unrestricted subsidiaries not included in income			$ 32
Proceeds from Sale of Productive Assets	$ 40,000,000	$ 40,000,000

Transactions with Related Par_3

Transactions with Related Parties (Schedule of Transactions With Related Parties) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Total revenues	$ 3,176,996	$ 2,788,957	$ 2,125,476
Poseidon Oil Pipeline Company
Related Party Transaction [Line Items]
Equity investment, ownership percentage	64%
Affiliated Entity
Related Party Transaction [Line Items]
Total revenues	$ 18,713	14,606	13,846
Expenses	9,124	1,057	965
Equity Method Investee
Related Party Transaction [Line Items]
Total revenues	0	418,232	280,935
Expenses	0	9,891	1,213
Other Receivables	1,900	2,400
CEO
Related Party Transaction [Line Items]
Expenses	$ 660	$ 660	$ 660

Transactions with Related Par_4

Transactions with Related Parties (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Total revenues	$ 3,176,996	$ 2,788,957	$ 2,125,476
Equity Method Investee
Related Party Transaction [Line Items]
Total revenues	0	418,232	280,935
Other Receivables	1,900	2,400
Equity Method Investee | Fees
Related Party Transaction [Line Items]
Total revenues	$ 10,000	$ 9,700	$ 9,400

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, 2023	Dec. 31, 2022	Dec. 31, 2021
(Increase) decrease in:
Accounts receivable	$ 159,426	$ (261,849)	$ (75,165)
Inventories	(37,566)	2,087	20,370
Deferred charges	48,835	41,634	27,390
Other current assets	(2,110)	(6,971)	(1,190)
Increase (decrease) in:
Accounts payable	(135,289)	152,138	44,119
Accrued liabilities	(29,122)	(14,857)	14,520
Net changes in components of operating assets and liabilities	$ 4,174	$ (87,818)	$ 30,044

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Payments of interest and commitment fees	$ 276.2	$ 236.9	$ 202
Capitalized interest	43.2	18.1	4.4
Cash paid for income taxes	0.9	1	0.7
Incurred liabilities for fixed and intangible asset additions	$ 172.7	$ 93.5	$ 51.7

Equity-Based Compensation Pla_3

Equity-Based Compensation Plans (Narrative) (Details) - 2010 Plan - Phantom Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in units)	74,106	70,068	71,340
Weighted average grant date fair value of phantom unit (in dollars per unit)	$ 10.26	$ 9.92	$ 8.83
Compensation expense	$ 1.2	$ 0.7	$ 1.4
Liability for compensation awards	$ 1.4	$ 2.1

Equity-Based Compensation Pla_4

Equity-Based Compensation Plans (Summary of Service-Based and Performance-Based Awards) (Details) - Service-Based Awards - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Phantom Units
Unvested at December 31, 2020 (in units)	220,132	208,518	165,662
Granted (in units)	74,106	70,068	71,340
Settled (in units)	(177,640)	(58,454)	(28,484)
Unvested at December 31, 2021 (in units)	116,598	220,132	208,518
Average Grant Date Fair Value
Unvested at December 31, 2020 (in dollars unit)	$ 8.97	$ 10.67	$ 11.19
Granted (in dollars per unit)	10.26	9.92	8.83
Settled (in dollars per unit)	7.46	16.17	9.05
Unvested at December 31, 2021 (in dollars per unit)	$ 12.09	$ 8.97	$ 10.67
Total Value (in thousands)
Unvested at December 31, 2020	$ 1,975	$ 2,225	$ 1,853
Granted	760	695	630
Settled	(1,325)	(945)	(258)
Unvested at December 31, 2021	$ 1,410	$ 1,975	$ 2,225

Major Customers and Credit Ri_2

Major Customers and Credit Risk (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Customer Concentration Risk | Revenue from Contracts with Customers | ANSAC
Concentration Risk [Line Items]
Concentration risk, percentage	15%	13%

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivatives Entered Into to Hedge Inventory or Fixed Price Purchase Commitments) (Details) gal in Thousands, bbl in Thousands, T in Thousands	12 Months Ended
	Dec. 31, 2023 MMBTU T $ / bbl $ / MMBTU $ / gal $ / units $ / T bbl gal
Sell (Short) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (bbls)	234
Weighted average contract price | $ / bbl	74.71
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (bbls)	8
Weighted average contract price | $ / bbl	74.89
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Contract volume (MMBTU) | MMBTU	210,000
Weighted average contract price | $ / MMBTU	2.54
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Fuel
Derivative [Line Items]
Contract volumes (MT) | T	0
Weighted average contract price (MT) | $ / T	0
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Contract volume (MMBTU) | MMBTU	0
Weighted average contract price | $ / bbl	0
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Options | Natural Gas
Derivative [Line Items]
Contract volumes (bbls)	6
Weighted average contract price | $ / MMBTU	0.75
Sell (Short) Contracts | Not qualifying or not designated as hedges under accounting rules | Commodity Option | Natural Gas and Natural Gas Liquids
Derivative [Line Items]
Contract volumes (bbls) | gal	0
Weighted average contract price | $ / gal	0
Buy (Long) Contracts | Designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (bbls)	29
Weighted average contract price | $ / bbl	74.89
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Crude Oil
Derivative [Line Items]
Contract volumes (bbls)	1
Weighted average contract price | $ / bbl	74.89
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Natural Gas
Derivative [Line Items]
Contract volume (MMBTU) | MMBTU	1,344,000
Weighted average contract price | $ / MMBTU	3.58
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Futures | Fuel
Derivative [Line Items]
Contract volumes (MT) | T	62
Weighted average contract price (MT) | $ / T	537.45
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Swap | Natural Gas
Derivative [Line Items]
Contract volume (MMBTU) | MMBTU	1,323,000
Weighted average contract price | $ / units	0.56
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Options | Natural Gas
Derivative [Line Items]
Contract volumes (bbls)	3
Weighted average contract price | $ / MMBTU	0.02
Buy (Long) Contracts | Not qualifying or not designated as hedges under accounting rules | Commodity Option | Natural Gas and Natural Gas Liquids
Derivative [Line Items]
Contract volumes (bbls) | gal	2,750
Weighted average contract price | $ / gal	0.33

Derivatives (Fair Value of Deri

Derivatives (Fair Value of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Liability Derivatives:
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Not Designated As Hedging Instrument | Commodity Derivatives
Asset Derivatives:
Gross amount of recognized assets	$ 1,235	$ 1,238
Gross amount offset in the Consolidated Balance Sheets	1,235	1,238
Net amount of assets presented in the Consolidated Balance Sheets	0	0
Liability Derivatives:
Net amount of liabilities presented in the Consolidated Balance Sheets	0	(5,844)
Not Designated As Hedging Instrument | Commodity Derivatives | Current Assets - Other(1)
Liability Derivatives:
Gross amount of recognized liabilities	(12,384)	(11,061)
Gross amount offset in the Consolidated Balance Sheets	12,384	5,217
Not Designated As Hedging Instrument | Swap | Current Assets - Other(1)
Asset Derivatives:
Gross amount of recognized assets	3,710	36,844
Not Designated As Hedging Instrument | Swap | Current Liabilities - Accrued Liabilities
Liability Derivatives:
Gross amount of recognized liabilities	(5,536)	(4,692)
Designated as Hedging Instrument | Commodity Derivatives
Asset Derivatives:
Gross amount of recognized assets	716	0
Gross amount offset in the Consolidated Balance Sheets	716	0
Net amount of assets presented in the Consolidated Balance Sheets	0	0
Liability Derivatives:
Net amount of liabilities presented in the Consolidated Balance Sheets	0	0
Designated as Hedging Instrument | Commodity Derivatives | Current Assets - Other(1)
Liability Derivatives:
Gross amount of recognized liabilities	(120)	0
Gross amount offset in the Consolidated Balance Sheets	$ 120	$ 0

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details)			3 Months Ended	12 Months Ended
	Sep. 01, 2022	Sep. 01, 2017	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Sep. 29, 2022 USD ($)	Mar. 01, 2019
Derivatives, Fair Value [Line Items]
Net broker receivables				$ 10,900,000	$ 4,000,000
Margin deposit assets				5,700,000	$ 3,800,000
Increase in variation margin deposits outstanding			$ 200,000	$ 5,200,000
Embedded Derivative Financial Instruments
Derivatives, Fair Value [Line Items]
Embedded derivative liability						$ 101,800,000
Class A Convertible Preferred Units
Derivatives, Fair Value [Line Items]
Threshold trading days to notify holders	30 days	30 days
Reset rate	10.75%			11.24%		11.24%
Basis spread							0.0200
Percentage below issue price	110%
Class A Convertible Preferred Units | LIBOR Rate
Derivatives, Fair Value [Line Items]
Reset rate						3.74%
Basis spread	0.0750					750

Derivatives (Effects on Consoli

Derivatives (Effects on Consolidated Statements of Operations and Other Comprehensive Income (Loss)) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives		$ 18,584,000
Embedded Derivative Financial Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives			$ 30,838,000
Level 3 | Embedded Derivative Financial Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Net loss for the period including earnings	$ 0	(18,584,000)	(30,838,000)
Commodity Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives	20,755,000	(7,416,000)	16,525,000
Swap | Soda and sulfur services operating costs
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives	(6,953,000)	(31,904,000)	(1,174,000)
Embedded Derivative Financial Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives			30,800,000
Designated as Hedging Instrument | Commodity Derivatives | Onshore facilities and transportation product costs
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives	(617,000)	(1,403,000)	7,634,000
Not Designated As Hedging Instrument | Commodity Derivatives | Onshore facilities and transportation product costs, soda and sulfur services operating costs
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized losses on valuation of embedded derivatives	$ 21,372,000	$ (6,013,000)	$ 8,891,000

Fair-Value Measurements (Fair V

Fair-Value Measurements (Fair Value of Financial Assets Liabilities Measured on Recurring Basis) (Details) - Fair Value, Recurring - Commodity Derivatives - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 1,951	$ 1,238
Liabilities	(12,504)	(11,061)
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	3,710	36,844
Liabilities	(5,536)	(4,692)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Liabilities	$ 0	$ 0

Fair-Value Measurements (Reconc

Fair-Value Measurements (Reconciliation of Changes in Derivatives Classified as Level 3) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net loss for the period including earnings	$ (18,584,000)
Reclassification to Mezzanine Equity	101,794,000
Embedded Derivative Financial Instruments
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net loss for the period including earnings		$ (30,800,000)
Embedded Derivative Financial Instruments
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net loss for the period including earnings		(30,838,000)
Level 3
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	(83,210,000)	(52,372,000)
Ending Balance	$ 0	$ (83,210,000)

Fair-Value Measurements (Narrat

Fair-Value Measurements (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Sep. 29, 2022	Sep. 01, 2022
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net loss for the period including earnings		$ (18,584,000)
Senior unsecured notes	$ 3,062,955,000	2,856,312,000
Fair value of debt	3,200,000,000	2,700,000,000
Principal	3,823,215,000	3,506,284,000
Unrealized gain (loss) on derivatives	$ (36,635,000)	$ 5,823,000	$ (30,700,000)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other expense, net	Other expense, net
Class A Convertible Preferred Stock Units
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Reset rate	11.24%			11.24%	10.75%
Minimum | Class A Convertible Preferred Stock Units
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Reset rate				8.75%
Maximum | Class A Convertible Preferred Stock Units
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Reset rate	11.24%
5.875% Alkali senior secured notes due 2042
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Principal	$ 400,000,000
Embedded Derivative Financial Instruments
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net loss for the period including earnings			(30,800,000)
Unrealized gain (loss) on derivatives		$ (18,600,000)	$ (30,800,000)
Measurement Input, Equity Volatility
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Embedded derivative feature	50

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023
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 ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in benefit obligation:
Benefit Obligation, beginning of year	$ 42,065,000	$ 55,934,000
Service Cost	3,119,000	5,181,000	$ 6,020,000
Interest Cost	2,205,000	1,804,000	1,576,000
Actuarial Gain (Loss)	1,358,000	(19,557,000)
Benefits Paid	(1,449,000)	(1,297,000)
Benefit Obligation, end of year	47,298,000	42,065,000	55,934,000
Change in plan assets:
Fair Value of Plan Assets, beginning of year	30,073,000	35,288,000
Actual Return on Plan Assets	5,270,000	(6,363,000)
Employer Contributions	3,100,000	2,445,000
Benefits Paid	(1,449,000)	(1,297,000)
Fair Value of Plan assets, end of year	36,994,000	30,073,000	$ 35,288,000
Funded Status at end of period	(10,304,000)	(11,992,000)
Amounts recognized in the Consolidated Balance Sheets:
Non-current assets	0	0
Current liabilities	0	0
Non-current Liabilities	(10,304,000)	(11,992,000)
Net Liability at end of year	(10,304,000)	(11,992,000)
Amounts recognized in accumulated other comprehensive income:
Prior Service Cost	4,215,000	4,702,000
Net actuarial gain	(12,196,000)	(10,816,000)
Amounts recognized in accumulated other comprehensive income:	$ (7,981,000)	$ (6,114,000)

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Contributions and Future Benefit Payments) (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Employer Contributions
Expected 2024 Contributions by Employer	$ 4,488
Future Expected Benefit Payments
2024	1,436
2025	1,750
2026	1,898
2027	2,072
2028	2,220
2029-2033	$ 13,166

Employee Benefit Plans (Compone

Employee Benefit Plans (Components of Net Periodic Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Service Cost	$ 3,119	$ 5,181	$ 6,020
Interest Cost	2,205	1,804	1,576
Expected Return on Assets	(2,099)	(1,959)	(1,831)
Amortization of Prior Service Cost	487	487	487
Actuarial Gain	(434)	0	0
Total Net Periodic Benefit Costs	$ 3,278	$ 5,513	$ 6,252

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value Assumptions) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Weighted average assumptions used to determine benefit obligation:
Discount Rate	5.16%	5.33%
Expected Long-term Rate of Return	6.69%	6.71%

Employee Benefit Plans (Asset T

Employee Benefit Plans (Asset Target Allocation) (Details)	Dec. 31, 2023
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target %	67%
Equity securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Actual %	58%
Equity securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Actual %	76%
Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Target %	20%
Fixed Income | Minimum
Defined Benefit Plan Disclosure [Line Items]
Actual %	11%
Fixed Income | Maximum
Defined Benefit Plan Disclosure [Line Items]
Actual %	29%
Alternative Investments
Defined Benefit Plan Disclosure [Line Items]
Target %	11%
Alternative Investments | Minimum
Defined Benefit Plan Disclosure [Line Items]
Actual %	2%
Alternative Investments | Maximum
Defined Benefit Plan Disclosure [Line Items]
Actual %	20%
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Target %	2%
Cash and cash equivalents | Minimum
Defined Benefit Plan Disclosure [Line Items]
Actual %	0%
Cash and cash equivalents | Maximum
Defined Benefit Plan Disclosure [Line Items]
Actual %	7%

Employee Benefit Plans (Fair _2

Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 36,994,000	$ 30,073,000	$ 35,288,000
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	5,212,000	4,592,000
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	24,612,000	20,838,000
Fixed income and other securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	7,170,000	4,643,000
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	36,994,000	30,073,000
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	5,212,000	4,592,000
Level 1 | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	24,612,000	20,838,000
Level 1 | Fixed income and other securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	7,170,000	4,643,000
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 | Fixed income and other securities
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 | Fixed income and other securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 0	$ 0

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current:
Federal	$ 211	$ 0	$ 0
State	836	815	690
Total current income tax expense	1,047	815	690
Deferred:
Federal	248	1,814	1,097
State	(1,314)	540	(117)
Total deferred income tax expense (benefit)	(1,066)	2,354	980
Income tax expense (benefit)	$ (19)	$ 3,169	$ 1,670

Income Taxes (Deferred Tax Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Net operating loss carryforwards	$ 13,631	$ 15,313
Right of use liabilities	36,148	0
Other	4,823	2,333
Total long-term deferred tax asset	54,602	17,646
Valuation allowances	(3,802)	(3,471)
Total deferred tax assets	50,800	14,175
Deferred tax liabilities:
Fixed assets	(2,408)	(1,730)
Intangible assets	(29,635)	(27,033)
Right of use assets	(36,150)	0
Other	(117)	(2,064)
Total long-term liability	(68,310)	(30,827)
Total deferred tax liabilities	(68,310)	(30,827)
Total net deferred tax liability	$ (17,510)	$ (16,652)

Income Taxes (Federal Statutory

Income Taxes (Federal Statutory Income Tax Rate to Income Before Income Taxes) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income (loss) from operations before income taxes	$ 146,328,000	$ 132,304,000	$ (136,362,000)
Partnership income (loss) not subject to federal income tax	(135,349,000)	(126,403,000)	140,092,000
Income subject to federal income taxes	10,979,000	5,901,000	3,730,000
Tax expense at federal statutory rate	2,306,000	1,239,000	783,000
State income taxes, net of federal tax	(467,000)	1,248,000	574,000
Return to provision, federal and state	(169,000)	44,000	(227,000)
Other	(2,077,000)	(18,000)	112,000
Valuation allowance	388,000	656,000	428,000
Income tax expense (benefit)	$ (19,000)	$ 3,169,000	$ 1,670,000
Effective tax rate on income (loss) from operations before income taxes	(0.01%)	2.40%	(1.20%)
Liability for uncertain tax positions	$ 0	$ 0	$ 0