Genesis Energy (GEL) 10-K 26 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 26, 2018	Jun. 30, 2017
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	GENESIS ENERGY LP
Entity Central Index Key	1,022,321
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Public Float			$ 3.3
Common Class A [Member]
Entity Common Stock, Shares Outstanding		122,539,221
Common Class B [Member]
Entity Common Stock, Shares Outstanding		39,997

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 9,041		$ 7,029
Accounts receivable—trade, net	495,449		224,682
Inventories	88,653		98,587
Other	42,890		29,271
Total current assets	636,033		359,569
FIXED ASSETS, at cost	5,601,015		4,763,396
Less: Accumulated depreciation	(734,986)		(548,532)
Net fixed assets	4,866,029		4,214,864
MINERALS LEASEHOLDS, net of accumulated depletion	564,506		0
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	125,283		132,859
EQUITY INVESTEES	381,550		408,756
INTANGIBLE ASSETS, net of amortization	182,406		204,887
GOODWILL	325,046		325,046
OTHER ASSETS, net of amortization	56,628		56,611
TOTAL ASSETS	7,137,481		5,702,592
CURRENT LIABILITIES:
Accounts payable—trade	270,855		119,841
Accrued liabilities	185,409		140,962
Total current liabilities	456,264		260,803
SENIOR SECURED CREDIT FACILITY	1,099,200		1,278,200
SENIOR UNSECURED NOTES, net of debt issuance costs	2,598,918		1,813,169
DEFERRED TAX LIABILITIES	11,913		15,971
DEFERRED TAX LIABILITIES	20,134		25,889
OTHER LONG-TERM LIABILITIES	256,571		204,481
Total liabilities	4,422,866		3,582,542
MEZZANINE CAPITAL
Class A Convertible Preferred Units, 22,411,728 issued and outstanding at December 31, 2017	697,151		0
COMMITMENTS AND CONTINGENCIES (Note 21)
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 117,979,218 units issued and outstanding at December 31, 2017 and 2016, respectively	2,026,147		2,130,331
Accumulated other comprehensive loss	(604)	[1]	0
Noncontrolling interests	(8,079)		(10,281)
Total partners' capital	2,017,464		2,120,050
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$ 7,137,481		$ 5,702,592
[1]	The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our Guarantor Subsidiaries.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Class A convertible preferred units issued (in shares)	22,411,728
Class A convertible preferred units outstanding (in shares)	22,411,728	0
Common units issued (in shares)	122,579,218	117,979,218
Common units outstanding (in shares)	122,579,218	117,979,218

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues [Abstract]
Offshore pipeline transportation services	$ 318,239	$ 334,679	$ 140,230
Sodium minerals and sulfur services	462,622	171,503	177,880
Marine transportation	205,287	213,021	238,757
Onshore facilities and transportation	1,042,229	993,290	1,689,662
Total revenues	2,028,377	1,712,493	2,246,529
COSTS AND EXPENSES:
Onshore facilities and transportation product costs	866,458	823,524	1,481,619
Onshore facilities and transportation operating costs	102,189	101,103	121,189
Marine transportation operating costs	154,606	142,551	135,200
Sodium minerals and sulfur services operating costs	333,918	91,443	96,806
Offshore pipeline transportation operating costs	72,065	79,624	39,713
General and administrative	66,421	45,625	64,995
Depreciation, depletion and amortization	252,480	222,196	150,140
Gain on sale of assets	(40,311)	0	0
Total costs and expenses	1,807,826	1,506,066	2,089,662
OPERATING INCOME	220,551	206,427	156,867
Equity in earnings of equity investees	51,046	47,944	54,450
Interest expense	(176,762)	(139,947)	(100,596)
Gain on basis step up on historical interest	0	0	332,380
Other expense, net	(16,715)	0	(17,529)
Income from operations before income taxes	78,120	114,424	425,572
Income tax benefit (expense)	3,959	(3,342)	(3,987)
NET INCOME	82,079	111,082	421,585
Net loss attributable to noncontrolling interests	568	2,167	943
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	82,647	113,249	422,528
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(21,995)	0	0
NET INCOME AVAILABLE TO COMMON UNITHOLDERS	$ 60,652	$ 113,249	$ 422,528
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
Basic and Diluted (in dollars per unit)	$ 0.50	$ 1	$ 4.10
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted (in units)	121,546	113,433	103,004

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 82,079	$ 111,082	$ 421,585
Other comprehensive loss:
Other comprehensive loss	(604)	0	0
Total Comprehensive loss	81,475	111,082	421,585
Comprehensive income attributable to non-controlling interests	568	2,167	943
Comprehensive income attributable to Genesis Energy, L.P.	$ 82,043	$ 113,249	$ 422,528

Consolidated Statements of Part

Consolidated Statements of Partners' Capital - USD ($) $ in Thousands	Total	Partners' Capital		Partners' CapitalNumber of Common Units	Noncontrolling Interest	Accumulated Other Comprehensive Loss
Partners' capital, units (in shares) at Dec. 31, 2014				95,029,000
Partners' capital, value at Dec. 31, 2014	$ 1,229,203	$ 1,229,203			$ 0	$ 0
Net income (loss)	421,585	422,528		$ 0	(943)	0
Noncontrolling interest from acquisition	(6,447)	0		0	(6,447)	0
Cash distributions to partners, net	(256,389)	(256,389)		0	0	0
Cash distributions to noncontrolling interests	(960)	0		$ 0	(960)	0
Issuance of units for cash, net, units				14,950,000
Issuance of units for cash, net	633,759	633,759			0	0
Other comprehensive loss	0
Partners' capital, units (in shares) at Dec. 31, 2015				109,979,000
Partners' capital, value at Dec. 31, 2015	2,020,751	2,029,101			(8,350)	0
Net income (loss)	111,082	113,249		$ 0	(2,167)	0
Cash distributions to partners, net	(310,039)	(310,039)		$ 0	0	0
Issuance of units for cash, net, units				8,000,000
Issuance of units for cash, net	298,020	298,020			0	0
Cash contributions from noncontrolling interests	236	0		$ 0	236	0
Other comprehensive loss	$ 0
Partners' capital, units (in shares) at Dec. 31, 2016	117,979,218			117,979,000
Partners' capital, value at Dec. 31, 2016	$ 2,120,050	2,130,331			(10,281)	0
Net income (loss)	82,079	82,647	[1]	$ 0	(568)	0
Cash distributions to partners, net	(321,875)	(321,875)		$ 0	0	0
Issuance of units for cash, net, units				4,600,000
Issuance of units for cash, net	140,513	140,513			0	0
Cash contributions from noncontrolling interests	2,770	0		$ 0	2,770	0
Other comprehensive loss	(604)	0		0	0	(604)
Distributions to preferred unitholders	$ (5,469)	(5,469)		$ 0	0	0
Partners' capital, units (in shares) at Dec. 31, 2017	122,579,218			122,579,000
Partners' capital, value at Dec. 31, 2017	$ 2,017,464	$ 2,026,147			$ (8,079)	$ (604)
Accumulated distributions to preferred unitholders	$ (22,000)
[1]	Net income (loss) includes $22 million attributable to preferred unitholders accumulated as of December 31, 2017.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 82,079	$ 111,082	$ 421,585
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	252,480	222,196	150,140
Provision for leased items no longer in use	12,589	0	0
Gain on sale of assets	(40,311)	0	0
Gain on basis step up on historical interest	0	0	(332,380)
Amortization and write-off of debt issuance costs and premium or discount	13,103	10,138	10,881
Amortization of unearned income and initial direct costs on direct financing leases	(13,747)	(14,395)	(14,979)
Payments received under direct financing leases	20,668	20,672	20,664
Equity in earnings of investments in equity investees	(51,046)	(47,944)	(54,450)
Cash distributions of earnings of equity investees	62,618	65,867	71,823
Non-cash effect of equity-based compensation plans	(5,775)	6,558	5,014
Deferred and other tax benefits	(4,060)	2,142	2,960
Unrealized (gains) losses on derivative transactions	10,943	1,287	(1,009)
Other, net	(10,839)	11,385	3,915
Net changes in components of operating assets and liabilities, net of acquisitions (See Note 15)	10,156	(90,650)	5,372
Net cash provided by operating activities	338,858	298,338	289,536
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(250,593)	(463,100)	(495,774)
Cash distributions received from equity investees—return of investment	20,280	21,353	25,645
Investments in equity investees	(4,647)	0	(3,045)
Acquisitions	(1,325,759)	(25,394)	(1,520,299)
Contributions in aid of construction costs	124	13,374	3,179
Proceeds from asset sales	85,722	3,609	2,811
Other, net	0	(151)	(1,976)
Net cash used in investing activities	(1,474,873)	(450,309)	(1,989,459)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,458,700	1,115,800	1,525,050
Repayments on senior secured credit facility	(1,637,700)	(952,600)	(960,450)
Proceeds from issuance of senior unsecured notes	1,000,000	0	1,139,718
Proceeds from issuance of Class A convertible preferred units, net	726,419	0	0
Repayment of senior unsecured notes	(204,830)	0	(350,000)
Debt issuance costs	(25,913)	(1,578)	(28,901)
Issuance of common units for cash, net	140,513	298,020	633,759
Contributions (distributions) from (to) noncontrolling interests	2,770	236	(960)
Distributions to common unitholders	(321,875)	(310,039)	(256,389)
Other, net	(57)	(1,734)	(471)
Net cash provided by financing activities	1,138,027	148,105	1,701,356
Net increase (decrease) in cash and cash equivalents	2,012	(3,866)	1,433
Cash and cash equivalents at beginning of period	7,029	10,895	9,462
Cash and cash equivalents at end of period	$ 9,041	$ 7,029	$ 10,895

Organization

Organization	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization We are a growth-oriented master limited partnership focused on the midstream segment of the crude oil and natural gas industry, as well as sodium minerals and sulfur services, in the Gulf Coast region of the United States, Wyoming and the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, Alkali Business, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, soda ash production, marketing and selling business (the "Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into transition service agreements to facilitate the transition of operations and uninterrupted services for both employees and customers. We report the results of our Alkali Business in our renamed sodium minerals and sulfur services segment, which includes our Alkali Business as well as our legacy refinery services operations. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. Our disclosures related to prior periods have been recast to reflect our reorganized segments. These four divisions that constitute our reportable segments consist of the following: • Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico; • Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, soda ash production, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly pronounced "nash"); • Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO2; and • Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 and our results of operations, statements of comprehensive income, changes in partners’ capital and cash flows for the years ended December 31, 2017 , 2016 and 2015 . 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 a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29% interest in Odyssey Pipeline L.L.C. (or "Odyssey"). We account for our investments in these joint ventures by the equity method of accounting. See Notes 3 and 8 . Use of Estimates The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We have no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. Inventories Our inventories are valued at the lower of cost or net realizable value. With the exception of our Alkali Business, cost is determined principally under the average cost method within specific inventory pools. Within our Alkali Business, the cost of inventories are determined using the FIFO, except for materials and supplies which are recorded at average cost, and raw materials which are recorded at standard cost. 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, 5 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 10 years for buildings and improvements, office equipment, furniture and fixtures and other equipment. Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost. Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, the costs incurred to develop such property through the commencement of production are capitalized. Deferred Charges on Marine Transportation Assets Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last. Asset Retirement Obligations Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO 2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. Accretion of the discount increases the liability and is recorded to expense. See Note 6 . Direct Financing Leasing Arrangements For our direct financing leases, we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in onshore facilities and transportation revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets. We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit rating and financial position of the lessee. See Note 7 . Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We are amortizing our customer and supplier relationships, contract agreements, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are being amortized on a straight-line basis. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with the issuance of long-term debt and certain amendments to our credit facilities 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 book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings may be necessary to reduce the carrying value of the goodwill to its implied fair value. In the event that we determine that goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made. No goodwill impairment has occurred in any of the periods presented. See Note 9 for further information. Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred. Equity-Based Compensation Our phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the market price of our common units. Our phantom units include both service-based and performance-based awards. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. See Note 16 for more information on these plans. Revenue Recognition Offshore Pipeline Transportation—Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenues from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenues from offshore platform services are recognized in the period the services are provided. Revenue from commodity charges is based on a fee per unit of volume (typically per MMcf of natural gas or per barrel of crude oil) delivered to the platform multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers. Product Sales—Revenues from the sale of crude oil, petroleum products and CO 2 by our onshore facilities and transportation segment, and caustic soda, NaHS, soda ash and other alkali products by our sodium minerals and sulfur services segment are recognized when title to the inventory is transferred to the customer, pricing is fixed and determinable, collectability is reasonably assured and there are no further significant obligations for future performance by us. Most frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although in certain situations, title transfers when the inventory is loaded for transportation to the customer. Our crude oil and petroleum products are typically sold at prices based off daily or monthly published prices. Many of our contracts for sales of NaHS incorporate the price of caustic soda in the pricing formulas. When necessary, accruals are made for sales returns, rebates and other allowances. Rail Facility Loading and Unloading Revenues—Revenues based on a per barrel fee from the loading and/or unloading of crude oil at our rail facilities is recognized as the crude oil enters or exits the railcars. Onshore Pipeline Transportation—Revenues from transportation of crude oil by our pipelines are based on actual volumes at a published tariff. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to the specifications outlined in our regulated tariffs. Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline revenues. In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines (onshore and offshore) due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs and agreements include the right for us to make volumetric deductions from the shippers for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances. 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, based on prevailing market prices at that time. 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 that we must make to replace the lost volumes. We reflect inventories in the Consolidated Financial Statements at the lower of the recorded value or the market value at the balance sheet date. We value liabilities to replace crude oil at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value. Marine Transportation—Revenues from the inland and offshore marine transportation of heavy refined petroleum products, including asphalt and crude oil, via our barges or vessels are recognized over the transit time of individual shipments 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 other specified operational costs are directly reimbursed by the customer under most of these contracts. Cost of Sales and Operating Expenses Onshore facilities and transportation operating costs include the cost to acquire the product and the associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and other vessels , including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein. When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as onshore facilities and transportation revenues. Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often rebillable and passed through to the customer. The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda. Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines. Income Taxes We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner. Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations. As further discussed in Note 22 , "Income Taxes," on December 22, 2017, the Tax Cuts and Jobs Act (“Act”) was signed into law which enacts significant changes to U.S. tax and related laws. U.S. state or other regulatory bodies have not finalized potential changes to existing laws and regulations which may result from the new U.S. tax and related laws. In accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin No. 118 (“SAB No. 118”), the Company has recorded provisional estimates to reflect the effect of the provisions of the recently enacted U.S. tax and related laws on the Partnership’s income tax assets and liabilities as of December 31, 2017 . Derivative Instruments and Hedging Activities When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. In addition, we have determined that certain provisions in our Class A Convertible Preferred units represent an embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods being recorded in our Consolidated Statements of Operations. See Note 1 8 for further information on these items. Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature. Pension benefits As a result of our acquisition of our Alkali Business, we now sponsor a defined benefit plan. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income or loss. Business Acquisitions For acquired businesses, we apply the acquisition method and generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. See Note 3 for more information regarding our acquisition accounting and recording of acquisition costs. Recent and Proposed Accounting Pronouncements In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective transition method. In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved early adoption of the standard, but not before the original effective date of December 15, 2016. As a result of our process of evaluating the impact of this guidance on each type of revenue contract entered into with customers, we have determined that the adoption of this guidance will have an immaterial impact on revenues and costs in certain of our revenue streams including our legacy sulfur removal operations relating to our NaHS business. We expect these items to have an even less significant impact on net income on a go forward basis. We have also identified certain contracts or elements of contracts for product loss allowances and tiered pricing that will be impacted. These items will not have a material impact on our financial statements. We are adopting this guidance by using the modified retrospective approach, effective January 1, 2018, by recognizing the cumulative effect of applying the guidance for periods prior to January 1, 2018 to the opening balance of Partner’s Capital. Management has concluded the estimated cumulative effect to be recorded is not material. In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements. In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this guidance. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We expect this guidance to have an impact on how we report our operating and investing cash flows from certain cash receipts and payments, particularly relating to cash distributions received from certain of our equity investees. In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We adopted this guidance and it did not have an impact on our consolidated financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions	Acquisitions Alkali Business On September 1, 2017 , we acquired our Alkali Business for approximately $1.325 billion (inclusive of approximately $105 million in working capital). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na 2 CO 3 ), as basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. To finance that transaction and the related costs, we used proceeds from (i) a $550 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance and underwriting fees, (ii) a $750 million private placement of Class A Convertible Preferred units in September 2017, generating net proceeds of $726.4 million , (iii) borrowings under our revolving credit facility and (iv) cash on hand. We have reflected the financial results of our Alkali Business in our sodium minerals and sulfur services segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Those preliminary fair values were developed by management with the assistance of a third-party valuation firm and are subject to change pending a final valuation report and final determination of any other purchase price adjustments. Certain changes were made in our preliminary purchase price allocation at December 31, 2017, as compared to what we had previously disclosed in our third quarter 2017 Form 10-Q. These changes principally relate to reclassifications made between mineral leaseholds and fixed assets as a result of further progress in our valuation process. We expect to finalize the purchase price allocation for this transaction during the first half of 2018. The preliminary allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Accounts receivable 138,258 Inventories 34,929 Other current assets 13,254 Fixed assets 663,217 Mineral leaseholds 566,019 Intangible assets 800 Other assets 3,612 Accounts payable (44,547 ) Accrued Liabilities (36,884 ) Other long-term liabilities (13,658 ) Total Purchase Price $ 1,325,000 Fixed assets identified in connection with our valuation and preliminary purchase price allocation include the related facilities, machinery and equipment associated with our Alkali Business, principally at our Green River, Wyoming operations. These assets will be depreciated under the straight line method and have useful lives ranging from 2 to 30 years. Mineral leaseholds include the trona reserves at our Green River, Wyoming facility and are depleted over their useful lives as determined by the units of production method. Other long-term liabilities contains various items including assumed employee benefit plan obligations. Other items principally consist of working capital items of our Alkali Business as acquired on September 1, 2017. Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017 , the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Year Ended 2017 Revenues 277,011 Net income 42,014 The table below presents selected unaudited pro forma financial information incorporating the historical results of our Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2015 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of our trona and trona-based exploring, mining, processing, producing, marketing and selling business and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Alkali Business acquisition been completed on January 1, 2015 . Pro forma net income includes the effects of distributions on preferred units and interest expense on incremental borrowings. The dilutive effect of Class A Preferred Units is calculated using the if-converted method. Year Ended 2017 2016 2015 Pro forma consolidated financial operating results: Revenues $ 2,549,438 $ 2,498,293 $ 3,043,529 Net Income Attributable to Genesis Energy, L.P. 84,010 120,515 416,118 Net Income Available to Common Unitholders 18,953 57,057 351,436 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 $ 1.00 $ 4.10 Pro forma net income per common unit, basic $ 0.16 $ 0.50 $ 3.41 Pro forma net income per common unit, dilutive $ 0.16 $ 0.50 $ 3.33 As relating to our Alkali Business acquisition, we have incurred approximately $12.0 million in acquisition related costs through December 31, 2017. Such costs are included as "General and Administrative costs" on our Consolidated Statement of Operations. Enterprise Offshore On July 24, 2015 , we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its affiliates for approximately $1.5 billion , subject to certain adjustments. That business includes interests in offshore crude oil and natural gas pipelines and six offshore hub platforms, including a 36% interest in the Poseidon Oil Pipeline System, a 50% interest in the Southeast Keathley Canyon Oil Pipeline System, and a 50% interest in the Cameron Highway Oil Pipeline System. To finance that transaction, in July 2015, we issued 10,350,000 common units in a public offering that generated proceeds of $437.2 million net of underwriter discounts and $750 million aggregate principal amount of 6.75% senior unsecured notes due 2022 that generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The remainder of that transaction was financed with borrowings under our senior secured credit facility. We have reflected the financial results of the acquired business in our offshore pipeline transportation segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Those fair values were developed by management with the assistance of a third-party valuation firm. The purchase price allocation for this transaction has been finalized. Our finalized purchase price allocation remains unchanged from what was disclosed in the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2016. The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Cash $ 1,270 Accounts receivable 29,768 Inventories 600 Other current assets 10,432 Fixed assets 1,225,685 Intangible assets 79,050 Equity investees 352,535 Other assets 1,966 Accounts payable (6,110 ) Accrued liabilities (18,662 ) Other long-term liabilities (161,412 ) Noncontrolling interest 6,447 Total purchase price $ 1,521,569 Fixed assets identified in connection with our valuation and purchase price allocation includes crude oil pipelines, natural gas pipelines and related assets. We will depreciate these assets on a straight line basis over estimated useful lives ranging from 2 to 35 years depending on the nature of each asset. Intangible assets identified in connection with our valuation and purchase price allocation 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 will amortize these intangible assets on a straight line basis over an estimated useful life of 19 years. In connection with our valuation and purchase price allocation, we have identified asset retirement obligations ("AROs") relating to the crude oil pipelines, natural gas pipelines and related assets with a preliminary fair value of $158.2 million . Of these AROs, $9.8 million of retirement costs were estimated to be incurred within the next year and thus were included in accrued liabilities in the table above, as well as on our Consolidated Balance Sheet at December 31, 2015. The remainder of the AROs recorded as a result of our Enterprise acquisition are included within "Other long-term liabilities" in the table above, as well as on our Consolidated Balance Sheet. See further discussion of AROs assumed as a result of our Enterprise acquisition in Note 6 . Noncontrolling interest as shown in the table above relates to the fair value assigned to the 20% ownership interest of our joint venture partner in Independence Hub, LLC, a consolidated subsidiary acquired as a result of our Enterprise acquisition in which we have an 80% ownership interest. Our Consolidated Financial Statements include the results of our acquired offshore pipeline transportation business since July 24, 2015 , the effective closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Year Ended 2015 Revenues $ 101,444 Net income $ 58,805 The table below presents selected unaudited pro forma financial information incorporating the historical results of our newly acquired offshore pipeline transportation assets. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2015 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of the Enterprise offshore pipelines and services businesses and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Enterprise acquisition been completed on January 1, 2015. Year Ended Pro forma consolidated financial operating results: 2015 Revenues $ 2,421,989 Net Income Attributable to Genesis Energy L.P. $ 425,363 Basic and diluted earnings per unit: As reported net income per unit $ 4.09 Pro forma net income per unit $ 3.91 As relating to our Enterprise acquisition, we incurred approximately $15 million in acquisition related costs through December 31, 2015 and incurred an additional $1 million during the year ended December 31, 2016. Such costs are included as "General and Administrative costs" on our Unaudited Condensed Consolidated Statement of Operations.

Receivables

Receivables	12 Months Ended
	Dec. 31, 2017
Accounts Receivable, Net, Current [Abstract]
Receivables	Receivables Accounts receivable – trade, net consisted of the following: December 31, 2017 2016 Accounts receivable - trade $ 503,917 $ 231,187 Allowance for doubtful accounts (8,468 ) (6,505 ) Accounts receivable - trade, net $ 495,449 $ 224,682 The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2017 2016 2015 Balance at beginning of period $ 6,505 $ 1,446 $ 2,973 Charged to costs and expenses 2,001 6,463 1,242 Amounts written off (38 ) (1,404 ) (2,769 ) Balance at end of period $ 8,468 $ 6,505 $ 1,446

Inventories

Inventories	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventories	Inventories The major components of inventories were as follows: December 31, 2017 2016 Petroleum products $ 8,731 $ 11,550 Crude oil 29,873 73,133 Caustic soda 5,755 4,593 NaHS 8,277 9,304 Raw materials - Alkali Operations 4,550 — Work-in-process - Alkali Operations 7,355 — Finished goods, net - Alkali Operations 14,075 — Materials and supplies, net - Alkali Operations 10,030 — Other 7 7 Total $ 88,653 $ 98,587 Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were no t recorded below cost as of December 31, 2017 and December 31, 2016 . Materials and supplies include chemicals, maintenance supplies, and spare parts which will be consumed in the mining of trona ore and production of soda ash processes.

Fixed Assets and Asset Retireme

Fixed Assets and Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Crude oil pipelines and natural gas pipelines and related assets $ 3,028,657 $ 2,901,202 Alkali facilities, machinery, and equipment 497,601 — Onshore facilities, machinery, and equipment 692,364 427,658 Transportation equipment 21,483 17,543 Marine vessels 918,953 863,199 Land, buildings and improvements 223,186 55,712 Office equipment, furniture and fixtures 18,112 9,654 Construction in progress 151,768 440,225 Other 48,891 48,203 Fixed assets, at cost 5,601,015 4,763,396 Less: Accumulated depreciation (734,986 ) (548,532 ) Net fixed assets $ 4,866,029 $ 4,214,864 Mineral Leaseholds Our Mineral Leaseholds, as relating to our recently acquired Alkali Business, consist of the following: December 31, Mineral leaseholds 566,019 Less: Accumulated depletion (1,513 ) Mineral leaseholds, net $ 564,506 Depreciation expense was $226.0 million , $194.0 million and $124.2 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Depletion expense was $1.5 million for the year ended December 31, 2017 , with no similar expense in 2016 and 2015 . During 2017, we sold certain non-core natural gas gathering and platform assets in the Gulf of Mexico included in our offshore pipeline transportation services segment, as well as certain onshore terminal facilities in West Texas included in our onshore facilities and transportation segment. These sales resulted in total gains on asset sales of $40.3 million for the year ended December 31, 2017. 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, 2015 $ 188,662 AROs arising from the acquisition and consolidation of a previously held equity method investment 20,940 Accretion expense 10,800 Revisions in timing and estimated costs of AROs (2,254 ) Settlements (4,422 ) December 31, 2016 213,726 Accretion expense 11,008 Revisions in timing and estimated costs of AROs 7,146 Acquisitions 131 Divestitures (7,649 ) Settlements (26,415 ) Other 240 December 31, 2017 $ 198,187 At December 31, 2017 and December 31, 2016 , $20.9 million and $22.4 million are included as current in "Accrued liabilities" on our Consolidated Balance Sheet, respectively. The remainder of the ARO liability at each period is included in "Other long-term liabilities" on our Consolidated Balance Sheet. With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated: 2018 $ 10,799 2019 $ 9,760 2020 $ 9,429 2021 $ 10,069 2022 $ 10,753 Certain of our unconsolidated affiliates have AROs recorded at December 31, 2017 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.

Net Investment in Direct Financ

Net Investment in Direct Financing Leases	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Net Investment In Direct Financing Leases	Net Investment in Direct Financing Leases Our direct financing leases include a lease of the Northeast Jackson Dome (“NEJD”) Pipeline. Under the terms of the agreement, we are paid quarterly payments, which commenced August 2008 . These quarterly payments are fixed at approximately $20.7 million per year during the lease term at an interest rate of 10.25% . At the end of the lease term in 2028 , we will convey all of our interests in the NEJD Pipeline to the lessee for a nominal payment. There are requirements in our leases that would provide credit support should the credit rating of our lessee fall to certain levels, and at December 31, 2017, the required credit support has been provided. The following table lists the components of the net investment in direct financing leases: December 31, 2017 2016 Total minimum lease payments to be received $ 215,884 $ 236,495 Unamortized initial direct costs 950 1,107 Less unearned income (83,918 ) (97,822 ) Net investment in direct financing leases 132,916 139,780 Less current portion (included in other current assets) (7,633 ) (6,921 ) Long-term portion of net investment in direct financing leases $ 125,283 $ 132,859 At December 31, 2017 , minimum lease payments to be received for each of the five succeeding fiscal years are $20.7 million .

Equity Investees

Equity Investees	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 , the unamortized differences in carrying value totaled $382.4 million and $398.1 million , respectively. We amortize the differences in carrying value as a change in equity earnings. As part of our Enterprise acquisition, we increased our ownership interest in each of Cameron Highway Oil Pipeline Company ("CHOPS") and Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO") from 50% to 100% . Consequently, these entities were reflected as equity investees until July 24, 2015, at which point they became fully consolidated wholly owned subsidiaries. Upon consolidation, we recorded a $332.4 million non-cash gain due to the step up in basis on our historical interest. Also, as part of our Enterprise acquisition, our ownership interest in Poseidon Oil Pipeline Company, LLC ("Poseidon") increased from 28% to 64% . We also acquired a 50% ownership interest in Deepwater Gateway, LLC and a 25.7% interest in Neptune Pipeline Company, LLC. These additional interests in Deepwater Gateway, LLC and Neptune Pipeline Company, LLC were accounted for as equity investments from the acquisition date of July 24, 2015. In the first quarter of 2016, we purchased the remaining 50% interest in Deepwater Gateway, LLC for approximately $26.0 million (including adjustments for working capital), increasing our ownership interest to 100% . Consequently, we now consolidate Deepwater Gateway, LLC instead of accounting for our interest under the equity method. The following table presents information included in our Consolidated Financial Statements related to our equity investees. Year Ended December 31, 2017 2016 2015 Genesis’ share of operating earnings $ 66,814 $ 63,805 $ 17,157 Amortization of differences attributable to Genesis' carrying value of equity investments (15,768 ) (15,861 ) 37,293 Net equity in earnings $ 51,046 $ 47,944 $ 54,450 Distributions received $ 82,898 $ 87,220 $ 97,468 The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis) including the effects of the change in our ownership interest due to the Enterprise and Deepwater acquisitions as previously discussed: December 31, 2017 2016 BALANCE SHEET DATA: Assets Current assets $ 34,381 $ 35,375 Fixed assets, net 362,214 365,563 Other assets 14,927 3,177 Total assets $ 411,522 $ 404,115 Liabilities and equity Current liabilities $ 23,289 $ 23,928 Other liabilities 249,610 230,327 Equity 138,623 149,860 Total liabilities and equity $ 411,522 $ 404,115 Year Ended December 31, 2017 2016 2015 INCOME STATEMENT DATA: Revenues $ 191,078 $ 193,038 $ 189,941 Operating Income $ 139,604 $ 122,836 $ 12,191 Net Income $ 134,479 $ 118,175 $ 7,810 Poseidon's revolving credit facility Borrowings under Poseidon’s revolving credit facilities, which was amended and restated in February 2015, are primarily used to fund spending on capital projects. The February 2015 credit facility is non-recourse to Poseidon’s owners and secured by its assets. The February 2015 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these consolidated financial statements.

Intangible Assets, Goodwill and

Intangible Assets, Goodwill and Other Assets	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 : December 31, 2017 December 31, 2016 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Sodium Minerals and Sulfur Services: Customer relationships 5 $ 94,654 $ 92,493 $ 2,161 $ 94,654 $ 89,756 $ 4,898 Licensing agreements 6 38,678 36,528 2,150 38,678 34,204 4,474 Non-compete agreement 3 800 89 711 — — — Segment total 134,132 129,110 5,022 133,332 123,960 9,372 Onshore Facilities & Transportation: Customer relationships 5 35,430 35,082 348 35,430 33,676 1,754 Intangibles associated with lease 15 13,260 4,933 8,327 13,260 4,459 8,801 Segment total 48,690 40,015 8,675 48,690 38,135 10,555 Marine contract intangible 5 27,000 11,700 15,300 27,000 6,300 20,700 Offshore pipeline contract intangibles 19 158,101 20,109 137,992 158,101 11,788 146,313 Other 5 28,900 13,483 15,417 28,569 10,622 17,947 Total $ 396,823 $ 214,417 $ 182,406 $ 395,692 $ 190,805 $ 204,887 The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services. The onshore facilities and transportation lease relates to a terminal facility in Shreveport, Louisiana. The marine contract intangible relates to the contracts we assumed in the purchase of the M/T American Phoenix in November 2014. The offshore pipeline contract intangibles relate to customer contracts surrounding certain transportation agreements with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline identified in connection with our purchase price allocation surrounding the Enterprise Acquisition. We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. The onshore facilities and transportation lease, marine contract, offshore pipeline contract intangibles and other intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $23.6 million , $24.3 million and $20.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2018 2019 2020 2021 2022 Sodium Minerals and Sulfur Services: Customer relationships $ 2,161 $ — $ — $ — $ — Licensing agreements 2,150 — — — — Non Compete 267 267 177 — — Onshore Facilities & Transportation: Customer relationships 41 39 38 37 35 Intangibles associated with lease 474 474 474 474 474 Marine contract intangibles 5,400 5,400 4,500 — — Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 2,974 2,952 2,921 1,810 1,652 Total $ 21,788 $ 17,453 $ 16,431 $ 10,642 $ 10,482 Goodwill The carrying amount of goodwill by business segment at both December 31, 2017 and 2016 was $301.9 million in sodium minerals and sulfur services and $23.1 million in onshore facilities and transportation. We have no t recognized any impairment losses related to goodwill for any of the periods presented. Other Assets Other assets consisted of the following: December 31, 2017 2016 CO 2 volumetric production payments, net of amortization $ 2,175 $ 3,503 Deferred marine charges, net (1) 30,246 27,710 Other deferred costs and deposits 24,207 25,398 Other assets, net of amortization $ 56,628 $ 56,611 (1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies ( Note 2 ) The CO 2 assets are being amortized on a units-of-production method. We recorded amortization of $1.3 million in 2017 , $3.9 million in 2016 and $5.9 million in 2015 .

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt At December 31, 2017 and 2016 , our obligations under debt arrangements consisted of the following: December 31, 2017 December 31, 2016 Principal Unamortized Discount and Debt Issuance Costs Net Value Principal Unamortized Discount and Debt Issuance Costs Net Value Senior secured credit facility $ 1,099,200 $ — $ 1,099,200 $ 1,278,200 $ — 1,278,200 5.750% senior unsecured notes 145,170 1,303 143,867 350,000 4,163 345,837 6.750% senior unsecured notes 750,000 16,077 733,923 750,000 19,296 730,704 6.000% senior unsecured notes 400,000 5,691 394,309 400,000 6,758 393,242 5.625% senior unsecured notes 350,000 5,717 344,283 350,000 6,614 343,386 6.500% senior unsecured notes 550,000 9,462 540,538 — — — 6.250% senior unsecured notes 450,000 $ 8,002 441,998 — — — Total long-term debt $ 3,744,370 $ 46,252 $ 3,698,118 $ 3,128,200 $ 36,831 $ 3,091,369 Senior Secured Credit Facility In July 2017, we amended our credit agreement to, among other things, make certain technical amendments related to the financing of our acquisition of our Alkali Business. The key terms for rates under our $1.7 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows: • The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At December 31, 2017 , the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Eurodollar rate borrowings. • Letter of credit fees range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2017 , our letter of credit rate was 2.75% . • We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio ( 0.50% at December 31, 2017 ). • Our credit facility contains a $300 million accordion feature, giving us the ability to expand the size of the facility up to $2.0 billion for acquisitions or growth projects, subject to lender consent. Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics—a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to EBITDA (as defined and adjusted in accordance with the credit facility) and cannot exceed 5.75 to 1.00 . Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot exceed 3.75 to 1.00 . Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense and must be greater than 3.00 to 1.00 ( 2.75 to 1.00 during an acquisition period). At December 31, 2017 , we had $1.1 billion borrowed under our credit facility, with $29.0 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $1.0 million was outstanding at December 31, 2017 . Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of May 9, 2022 . The total amount available for borrowings under our credit facility at December 31, 2017 was $599.8 million . Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Senior Unsecured Notes On February 8, 2013 , we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes"). Our 2021 Notes were sold at face value. Interest payments are due on February 15 and August 15 of each year. Our 2021 Notes mature on February 15, 2021 . The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes. On December 11, 2017, $204.8 million of these notes were validly tendered and repaid upon the issuance of our $450 million unsecured notes issued on December 11, 2017 as discussed below. A total loss of approximately $6.2 million for the tender is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations. The remaining principal balance on these notes as of December 31, 2017 is $145.2 million , which is expected to be fully redeemed on February 15, 2018. On May 15, 2014 , we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes due December 15, 2014 (the "2024 Notes"). Our 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. Our 2024 Notes mature on June 15, 2024 . The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes. On May 21, 2015 , we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes due May 15, 2023 (the "2023 Notes"). Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Our 2023 Notes mature on May 15, 2023 . We used a portion of the proceeds from those notes to effectively redeem all of our outstanding $350 million , 7.875% senior unsecured notes due 2018 , using a combination of public tender offer and our redemption rights relating to those notes. The aggregate principal amount of the 7.875% notes totaling $300.1 million were tendered and the remaining $49.9 million were redeemed in full. A total loss of approximately $19.2 million for the tender and redemption of notes is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations. On July 23, 2015 , we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due August 1, 2022 (the "2022 Notes"). Interest payments are due on February 1 and August 1 of each year with the initial interest payment due February 1, 2016. Our 2022 Notes mature on August 1, 2022 . That issuance generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for our Enterprise acquisition. On August 14, 2017, we issued $550 million in aggregate principal amount of 6.50% senior unsecured notes due October 1, 2025 (the "2025 Notes"). Interest payments are due April 1 and October 1 of each year with the initial interest payment due April 1, 2018. That issuance generated net proceeds of $540.1 million , net of issuance costs incurred. Our 2025 Notes mature on October 1, 2025 . The net proceeds were used to fund a portion of the purchase price for our acquisition of our Alkali Business. On December 11, 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due May 15, 2026 (the "2026 Notes"). Interest payments are due May 15 and November 15 of each year with the initial interest payment due May 15, 2018. That issuance generated net proceeds of $442.0 million , net of issuance costs incurred. Our 2026 Notes mature on May 15, 2026 . The net proceeds were used to redeem a portion of our outstanding principal on the 5.75% senior unsecured notes due 2021. Of the net proceeds, $204.8 million were used to redeem the portion of the 5.75% senior unsecured notes that were validly tendered, and the remaining balance was used for repaying a portion of the borrowings outstanding under our revolving credit facility. In addition, in January 2018 we called for the redemption of our remaining 2021 Notes. Refer to Note 25 where we discuss our subsequent events. 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. 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2025 Notes 2026 Notes Redemption right beginning on February 15, 2017 August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to February 15, 2017 August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Guarantees of our 2021, 2022, 2023, 2024, 2025 and 2026 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not a restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers and any other guarantor. Covenants and Compliance Our credit agreement and the indenture governing the senior notes contain cross-default provisions. Our credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, those agreements contain various covenants limiting our ability to, among other things: • incur indebtedness if certain financial ratios are not maintained; • grant liens; • engage in sale-leaseback transactions; and • sell substantially all of our assets or enter into a merger or consolidation. A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not restricted. As of December 31, 2017 , we were in compliance with the financial covenants contained in our credit facility and indenture.

Partners' Capital, Mezzanine an

Partners' Capital, Mezzanine and Equity Distributions	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Partners' Capital, Mezzanine and Equity Distributions	Partners’ Capital, Mezzanine Equity and Distributions At December 31, 2017 , our outstanding equity consisted of 122,539,221 Class A common units and 39,997 Class B common units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and, accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to certain exceptions. Distributions Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter: • less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to: • provide for the proper conduct of our business; • comply with applicable law, any of our debt instruments, or other agreements; or • provide funds for distributions to our unitholders for any one or more of the next four quarters; • plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. We paid distributions in 2018 , 2017 and 2016 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2015 4th Quarter February 12, 2016 $ 0.6550 $ 72,036 2016 1st Quarter May 13, 2016 $ 0.6725 $ 73,961 2nd Quarter August 12, 2016 $ 0.6900 $ 81,406 3rd Quarter November 14, 2016 $ 0.7000 $ 82,585 4th Quarter February 14, 2017 $ 0.7100 $ 83,765 2017 1st Quarter May 15, 2017 $ 0.7200 $ 88,257 2nd Quarter August 14, 2017 $ 0.7225 $ 88,563 3rd Quarter November 14, 2017 $ 0.5000 $ 61,290 4th Quarter February 14, 2018 $ 0.5100 $ 62,515 Equity Issuances and Contributions Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs. On March 24, 2017 , we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of offering costs, of approximately $140.5 million from that offering. On July 27, 2016 , we issued 8,000,000 Class A common units in a public offering at a price of $37.90 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $298.0 million from that offering. We used those proceeds to repay a portion of the borrowings outstanding under our credit facility. On July 22, 2015 , we issued 10,350,000 Class A common units in a public offering at a price of $43.77 per unit, which included the exercise by the underwriters of an option to purchase up to 1,350,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $437.2 million from that offering. We used the net proceeds to fund a portion of the purchase price for our Enterprise acquisition. On April 10, 2015 , we issued 4,600,000 Class A common units in a public offering at a price of $44.42 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $198.2 million from that offering. We used the net proceeds for general partnership purposes, including the repayment of a portion of the borrowings outstanding under our credit facility. The new common units issued in 2017 , 2016 and 2015 to the public for cash were as follows: Period Purchaser of Common Units Units Gross Unit Price Issuance Value Costs Net Proceeds March 2017 Public 4,600 $ 30.65 $ 140,990 $ (477 ) $ 140,513 July 2016 Public 8,000 $ 37.90 $ 303,200 $ (4,748 ) $ 298,452 July 2015 Public 10,350 $ 43.77 $ 453,020 $ (15,856 ) $ 437,164 April 2015 Public 4,600 $ 44.42 $ 204,332 $ (6,164 ) $ 198,168 Class A Convertible Preferred Units On September 1, 2017, we sold $750 million of Class A convertible preferred units ("preferred units") in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our preferred units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those preferred units. Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496 ), yielding a quarterly rate of 2.1875% (or $0.7374 ), subject to certain adjustments. With respect to any quarter ending on or prior to March 1, 2019, we have the option to pay to the holders of our preferred units the applicable distribution amount in cash, preferred units, or any combination thereof. If we elect to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We have elected to pay the distribution amount attributable to the quarter ended on September 30, 2017 in preferred units. For each quarter ending after March 1, 2019, we must pay all distribution amounts in respect of our preferred units in cash. From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of outstanding preferred units into our common units, subject to certain conditions; provided, however, that we will not be permitted to convert more than 7,416,498 of our preferred units in any consecutive twelve -month period. At any time after September 1, 2020, if we have fewer than 592,768 of our preferred units outstanding, we will have the right to convert each outstanding preferred unit into our common units at a conversion rate equal to the greater of (i) the then-applicable conversion rate and (ii) the quotient of (a) the Issue Price and (b) 95% of the volume-weighted average price of our common units for the 30-trading day period ending prior to the date that we notify the holders of our outstanding preferred units of such conversion. Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the holders of our common units is payable in cash, our preferred units will automatically convert into common units at a conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the product of (A) the sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our preferred units, and (B) a premium factor (ranging from 115% to 101% depending on when such transaction occurs) plus a prorated portion of unpaid partial distributions, and (ii) the volume weighted average price of the common units for the 30 trading days prior to the execution of definitive documentation relating to such change of control. In connection with other change of control events that do not meet the 90% cash consideration threshold described above, each holder of our preferred units may elect to (a) convert all of its preferred units into our common units at the then applicable conversion rate, (b) if we are not the surviving entity (or if we are the surviving entity, but our common units will cease to be listed), require us to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or if we are unable to cause such substantially equivalent securities to be issued, to convert its preferred units into common units in accordance with clause (a) above or exchanged in accordance with clause (d) below or convert at a specified conversion rate), (c) if we are the surviving entity, continue to hold our preferred units or (d) require us to exchange our preferred units for cash or, if we so elect, our common units valued at 95% of the volume-weighted average price of our common units for the 30 consecutive trading days ending on the fifth trading day immediately preceding the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101% and (y) the Issue Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points ; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25% of the then outstanding preferred units. Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110% , prior to September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its preferred units into common units initially on a one -for-one basis (subject to customary adjustments and an adjustment for accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a change of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser amount if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us. If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters, whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any distributions (subject to a limited exceptions for pro rata distributions on our preferred units and parity securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our preferred units with respect to rights upon distribution and/or liquidation (including our common units), or (b) issue any such junior or parity securities. If we fail to pay in full any preferred unit distribution after March 1, 2019 in respect of any two quarters, whether or not consecutive, then the preferred unit distribution amount will be reset to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to the then-current annualized distribution rate plus 200 basis points until such default is cured. In addition to their right to veto a Rate Reset Election under certain circumstances, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units; (ii) the right to purchase up to 50% of any parity securities on substantially the same terms offered to other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of our preferred units, and (iii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019. The Rate Reset Election of these preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. See further information in Note 18 . The preferred units themselves are classified as mezzanine capital on our Consolidated Balance Sheet. Accounting for the Class A Convertible Preferred Units The preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event which is outside of the Partnership's control. Therefore, they are presented as temporary equity in the mezzanine section of the Consolidated Balance Sheet. The preferred units have been recorded at their issuance date fair value, net of issuance costs. As the preferred units are not currently redeemable and the Partnership does not have plans or expect any events which constitute a change of control in the agreement, adjustment to the initial carrying amount is not necessary and would only be required if it becomes probable that the preferred units would become redeemable. Initial Measurement The preferred units were initially recognized at their issuance date fair value, net of issuance costs. As discussed above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long term liabilities on the Consolidated Balance Sheet as described below: Year Ended December 31, 2017 Transaction price, gross 750,000 Transaction cost to other third parties (23,581 ) Transaction price, net 726,419 Allocation of Net Transaction Price Preferred Units, net 691,969 Preferred Distribution Rate Reset Election ( Note 18 ) 34,450 726,419 Subsequent Measurement As discussed above, subsequent adjustment of the preferred units will not occur until it becomes probable that they would become redeemable. Once redemption becomes probable, the carrying amount of the preferred units would be adjusted 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. Preferred unit distributions are recognized on the date in which they are declared. In November 2017, we declared a $5.5 million distribution on the preferred units from September 1, 2017 (date of issuance) to September 30, 2017. This distribution was 100% paid in kind through the issuance of 162,234 additional preferred units. The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2017: Year Ended December 31, 2017 Balance as of December 31, 2016 — Issuance of Preferred Units, net 726,419 Allocation to Preferred Distribution Rate Reset Election ( Note 18 ) (34,450 ) Distribution paid-in-kind 5,469 Allocation of Distribution paid-kind to Preferred Distribution Rate Reset Election ( Note 18 ) (287 ) Balance as of December 31, 2017 697,151 Year Ended December 31, 2017 Balance as of December 31, 2016 — Issuance of Preferred Units 22,249,494 Distribution paid-in-kind 162,234 Balance as of December 31, 2017 22,411,728 Net income attributable to common unitholders is reduced by Preferred Unit distributions that accumulated during the period. During 2017, net income attributable to common unitholders was reduced by $22 million as a result of distributions that accumulated during the period. With respect to our Class A Convertible Preferred Units relating to the fourth quarter of 2017, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the issuance of an additional 490,252 Class A Convertible Preferred Units. This PIK amount equates to a distribution of $0.7374 per Class A Convertible Preferred Unit for the 2017 Quarter, or $2.9496 annualized. These distributions were paid on February 14, 2018 to unitholders holders of record at the close of business January 31, 2018.

Net Income Per Common Unit

Net Income Per Common Unit	12 Months Ended
	Dec. 31, 2017
Net Income per Common Unit [Abstract]
Net Income Per Common Unit	Net Income Per Common Unit Basic net income per common unit is computed by dividing net income, after considering income attributable to our Class A preferred unitholders, by the weighted average number of common units outstanding. The dilutive effect of the Class A Convertible Preferred units is calculated using the if-converted method. Under the if-converted method, the Class A Preferred units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the year ended December 31, 2017, the effect of the assumed conversion of the 22,411,728 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 and weighted average units used in computing basic and diluted net income per common unit (in thousands, except per unit amounts): Year Ended 2017 2016 2015 Net Income Attributable to Genesis Energy L.P. $ 82,647 $ 113,249 $ 422,528 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (21,995 ) — — Net Income Available to Common Unitholders $ 60,652 $ 113,249 $ 422,528 Weighted Average Outstanding Units 121,546 113,433 103,004 Basic and Diluted Net Income per Common Unit $ 0.50 $ 1.00 $ 4.10

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information Our operations consist of four operating segments (see Note 1 for discussion of segment reporting change): • Offshore Pipeline Transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico; • Sodium Minerals and Sulfur Services – trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly pronounced "nash"); • Onshore Facilities and Transportation – terminaling, blending, storing, marketing, and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products), and CO 2 ; and • Marine Transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America. Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States. We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total Year Ended December 31, 2017 Segment Margin (a) $ 317,540 $ 130,333 $ 96,376 $ 50,294 $ 594,543 Capital expenditures (b) $ 8,815 $ 1,354,469 $ 149,123 $ 68,414 $ 1,580,821 Revenues: External customers $ 319,455 $ 470,789 $ 1,044,083 $ 194,050 $ 2,028,377 Intersegment (c) (1,216 ) (8,167 ) (1,854 ) 11,237 $ — Total revenues of reportable segments $ 318,239 $ 462,622 $ 1,042,229 $ 205,287 $ 2,028,377 Year Ended December 31, 2016 Segment Margin (a) $ 336,620 $ 79,508 $ 83,364 $ 70,079 $ 569,571 Capital expenditures (b) $ 46,277 $ 2,274 $ 316,638 $ 78,804 $ 443,993 Revenues: External customers $ 332,514 $ 180,665 $ 993,103 $ 206,211 $ 1,712,493 Intersegment (c) 2,165 (9,162 ) 187 6,810 $ — Total revenues of reportable segments $ 334,679 $ 171,503 $ 993,290 $ 213,021 $ 1,712,493 Year Ended December 31, 2015 Segment Margin (a) $ 197,723 $ 80,246 $ 95,394 $ 103,222 $ 476,585 Capital expenditures (b) $ 1,527,320 $ 1,595 $ 409,687 $ 69,009 $ 2,007,611 Revenues: External customers $ 140,230 $ 187,257 $ 1,688,850 $ 230,192 $ 2,246,529 Intersegment (c) — (9,377 ) 812 8,565 $ — Total revenues of reportable segments $ 140,230 $ 177,880 $ 1,689,662 $ 238,757 $ 2,246,529 Total assets by reportable segment were as follows: December 31, 2017 December 31, 2016 December 31, 2015 Offshore pipeline transportation 2,486,803 2,575,335 2,623,478 Sodium minerals and sulfur services 1,848,188 395,043 394,626 Onshore facilities and transportation 1,927,976 1,875,403 1,615,335 Marine transportation 824,777 813,722 777,952 Other assets 49,737 43,089 48,208 Total consolidated assets $ 7,137,481 $ 5,702,592 $ 5,459,599 (a) A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for each year is presented below. (b) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. During the year ended December 31, 2016, capital expenditures in our offshore pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in Deepwater Gateway. Additionally, in 2015, there was $1.5 billion in capital spending to fund our Enterprise acquisition. Capital spending in this segment also included $2.5 million during the year ended December 31, 2015 representing capital contributions to our SEKCO pipeline to fund our share of the construction costs for its pipeline (as prior to our Enterprise acquisition in July 2015, we owned a 50% interest in the SEKCO pipeline with Enterprise owning the remaining 50% ). (c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions. Reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P.: Year Ended 2017 2016 2015 Total Segment Margin $ 594,543 $ 569,571 $ 476,585 Corporate general and administrative expenses (60,029 ) (40,905 ) (61,370 ) Depreciation, depletion, amortization and accretion (262,021 ) (230,563 ) (155,081 ) Interest expense (176,762 ) (139,947 ) (100,596 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (31,852 ) (39,276 ) (43,018 ) Non-cash items not included in Segment Margin (14,305 ) (3,221 ) 2,809 Cash payments from direct financing leases in excess of earnings (6,921 ) (6,277 ) (5,685 ) Gain on step up of historical basis — — 332,380 Loss on extinguishment of debt (6,242 ) — (19,225 ) Differences in timing of cash receipts for certain contractual arrangements (2) 17,540 13,253 6,359 Gain on sales of assets 40,311 — — Other, net (2,985 ) (6,044 ) (6,643 ) Non-cash provision for leased items no longer in use (12,589 ) — — Income tax expense 3,959 (3,342 ) (3,987 ) Net income attributable to Genesis Energy, L.P. $ 82,647 $ 113,249 $ 422,528 (1) Includes distributions attributable to the period and received during or promptly following such period. (2) Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

Transactions with Related Parti

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Transactions with Related Parties	Transactions with Related Parties Transactions with related parties were as follows: Year Ended December 31, 2017 2016 2015 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ 2,820 $ 3,097 $ 3,259 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,357 10,844 4,536 Revenues from product sales to ANSAC 124,536 — — Expenses: Amounts paid to our CEO in connection with the use of his aircraft $ 660 $ 660 $ 690 Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2) 986 1,007 464 Charges for services from ANSAC 2,242 — — (1) We own a 50% interest in Sandhill Group, LLC. (2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft, including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long-term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than what we could have expected to obtain in an arms-length transaction. Transactions with Unconsolidated Affiliates Poseidon As part of our Enterprise acquisition, we became the operator of Poseidon in the third quarter of 2015. We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the years ended December 31, 2017 , 2016 and 2015 reflect $8.4 million , $7.9 million and $3.9 million , respectively, of fees we earned through the provision of services under that agreement. At December 31, 2017 , and 2016 , Poseidon Oil Pipeline Company, LLC owed us $2.2 million and $1.6 million , respectively, for services rendered. ANSAC We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. (ANSAC), an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. ANSAC passes its costs through to its members using a pro rata calculation based on sales. Those costs include sales and marketing, employees, office supplies, professional fees, travel, rent, and certain other costs. Those transactions do not necessarily represent arm's length transactions and may not represent all costs we would otherwise incur if we operated the Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport. Net sales to ANSAC were $124.5 million during the period September 1, 2017 to December 31, 2017 . The costs charged to us by ANSAC, included in operating costs, were $2.2 million during the peri od September 1, 2017 to December 31, 2017 . As of December 31, 2017 , our receivables from and payables to ANSAC were: December 31 2017 Receivables: ANSAC $ 74,490 Payables: ANSAC $ 1,223

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 (Increase) decrease in: Accounts receivable $ (140,948 ) $ (9,859 ) $ 99,384 Inventories 49,055 (54,361 ) 3,811 Deferred charges (3,622 ) (3,902 ) (11,916 ) Other current assets (410 ) 3,059 6,417 Increase (decrease) in: Accounts payable 97,569 (17,426 ) (101,581 ) Accrued liabilities 8,512 (8,161 ) 9,257 Net changes in components of operating assets and liabilities $ 10,156 $ (90,650 ) $ 5,372 Payments of interest and commitment fees were $168.3 million , $157.4 million and $86.8 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. We capitalized interest of $15.0 million , $26.6 million and $17.1 million during the years ended December 31, 2017 , 2016 and 2015 . During the years ended December 31, 2017 , 2016 and 2015 , we paid taxes of $1.0 million , $1.3 million and $0.9 million . At December 31, 2017 , 2016 and 2015 , we had incurred liabilities for fixed and intangible asset additions totaling $39.7 million , $33.7 million and $68.6 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. During the year ended December 31, 2015 , as a result of our Enterprise acquisition, we acquired the 50% ownership interest in each of CHOPS and SEKCO as previously held by Enterprise, resulting in 100% ownership interest by us in each of these subsidiaries. As a result, we recorded a one-time $332.4 million non-cash gain from the step up in basis in our historical 50% ownership interest in each of CHOPS and SEKCO to fair value (resulting from the fair value assigned to the 50% ownership interest in each of CHOPS and SEKCO that we acquired from Enterprise, as derived from the preliminary purchase price allocation). This also results in the consolidation of CHOPS and SEKCO by us, resulting in the inclusion of the operating assets and liabilities on our Consolidated Balance Sheet. As 50% of the operating assets and liabilities of CHOPS and SEKCO were based on our historical interest with no cash impact, these amounts relating to our historical interest were not included in net changes in components of operating assets and liabilities in the Consolidated Statements of Cash Flows in 2015.

Equity-Based Compensation Plans

Equity-Based Compensation Plans	12 Months Ended
	Dec. 31, 2017
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 LTIP is adjusted to recognize changes in the estimated compensation cost and vesting. Management’s estimates of the fair value of these awards granted in 2017 are adjusted for assumptions about expected forfeitures of units prior to vesting. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. During 2017 , we granted 297,214 phantom units with tandem DERs at a weighted average grant fair value of $32.37 per unit. During 2016 , we granted 339,584 phantom units with tandem DERs at a weighted average grant date fair value of $30.71 per unit. The phantom units granted during 2017 and 2016 were both service-based and performance-based awards. The service-based awards vest on the third anniversary of the date of grant. Performance-based phantom unit awards granted in 2016 and 2017 will vest on the third anniversary of issuance, in an amount ranging from 50% to 150% of the targeted number of phantom units, if certain quarterly cash distribution per common unit targets are achieved in the fourth quarter of 2019 and 2020 , respectively. If the quarterly cash distribution per common unit is below the threshold target, all of the performance-based phantom units granted will be forfeited. During 2015 , we granted 212,825 phantom units with tandem DERs at a weighted average grant date fair value of $44.95 per unit. These phantom units are expected to be forfeited as the distribution per common unit is below the minimum target threshold. A summary of our phantom unit activity for our service-based and performance-based awards is set forth below: Service-Based Awards Performance-Based Awards Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Unvested at December 31, 2016 181,230 $ 40.59 $ 7,356 483,232 $ 38.82 $ 18,757 Granted 102,868 $ 32.27 3,320 194,346 $ 32.43 6,303 Forfeited (3,402 ) $ 37.22 (127 ) (17,410 ) $ 35.43 (617 ) Settled (40,859 ) $ 53.84 (2,200 ) (77,793 ) $ 54.18 (4,215 ) Unvested at December 31, 2017 239,837 $ 34.81 $ 8,349 582,375 $ 34.73 $ 20,228 At December 31, 2017 , we estimated the unrecognized compensation cost of our phantom awards to be approximately $2.1 million to be recognized over a weighted average period of approximately 1.5 years. We recorded a credit of $3.4 million and a charge of $8.9 million to compensation expense for the years ended December 31, 2017 and 2016 , respectively. Our liability for these awards totaled $3.2 million and $13.6 million at December 31, 2017 and 2016 , respectively. Equity-Based Compensation Plan Expense Equity-based compensation expense during the three years ended December 31, 2017 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2017 2016 2015 Onshore facilities and transportation operating costs $ (1,137 ) $ 1,688 $ 1,185 Marine transportation operating costs (483 ) 1,089 851 Sodium minerals and sulfur services operating costs (533 ) 547 227 Offshore pipeline operating costs (152 ) 681 94 General and administrative expenses (2,272 ) 4,575 4,565 Total $ (4,577 ) $ 8,580 $ 6,922

Major Customers and Credit Risk

Major Customers and Credit Risk	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Major Customers and Credit Risk	Major Customers and Credit Risk Due to the nature of our onshore facilities and transportation operations, a disproportionate percentage of our trade receivables constitute obligations of refiners, large crude oil producers and integrated oil companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of accounts owed by integrated and large independent energy companies with stable payment histories. The credit risk related to contracts which are traded on the NYMEX is limited due to daily margin requirements and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. During 2017 , 2016 and 2015 our largest customer was Shell Oil Company, which accounted for 13% , 12% , and 12% of total revenues, respectively. The revenues from Shell Oil Company in all three years relate primarily to our onshore facilities and transportation operations. In addition, as discussed in Note 14 , we are a member of ANSAC, an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. Given this relationship, a large portion of our soda ash production is sold to ANSAC. As such, a disproportionate amount of our trade receivables and sales in our sodium minerals and sulfur services segment are related to ANSAC.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity prices, primarily of crude oil, fuel oil and petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed. We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Consolidated Statement of Operations. In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets. At December 31, 2017 , we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. Sell (Short) Contracts Buy (Long) Contracts Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 297 — Weighted average contract price per bbl $ 57.70 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 223 152 Weighted average contract price per bbl $ 56.86 $ 57.30 Fuel oil futures: Contract volumes (1,000 bbls) 260 20 Weighted average contract price per bbl $ 55.01 $ 53.20 Crude oil options: Contract volumes (1,000 bbls) 80 45 Weighted average premium received $ 0.85 $ 0.24 Financial Statement Impacts The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements. Derivative Instrument Hedged Risk Impact of Unrealized Gains and Losses Consolidated Balance Sheets Consolidated Statements of Operations Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories Excess, if any, over effective portion of hedge is recorded in Onshore facilities and transportation costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged Not qualifying or not designated as hedges under accounting guidance: Commodity hedges consisting of crude oil, heating oil and natural gas futures and forward contracts and call options Volatility in crude oil and petroleum products prices - effect on market value of inventory or purchase commitments Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities Entire amount of change in fair value of derivative is recorded in Onshore facilities and transportation costs - product costs Preferred Distribution Rate Reset Election This instrument is not related to a risk, but is rather part of a host contract with the issuance of our Preferred Units Derivative is recorded in Other long-term liabilities Entire amount of change in fair value of derivative is recorded in Other income (expense) Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities. The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2017 and 2016 : Fair Value of Derivative Assets and Liabilities Fair Value Consolidated Balance Sheets Location December 31, 2017 December 31, 2016 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 505 $ 443 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (505 ) (443 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Total asset derivatives $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 54 $ 3,321 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (54 ) (3,321 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (45,209 ) — Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (1,203 ) $ (1,772 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,203 1,772 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (863 ) $ (9,506 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 338 7,589 Net amount of liabilities presented in the Consolidated Balance Sheets $ (525 ) $ (1,917 ) (1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other. (2) Refer to Note 11 and Note 19 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative. Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of December 31, 2017 , we had a net broker receivable of approximately $1.0 million (consisting of initial margin of $1.3 million decreased by $0.3 million of variation margin). As of December 31, 2016 , we had a net broker receivable of approximately $5.6 million (consisting of initial margin of $5.1 million increased by $0.5 million of variation margin). At December 31, 2017 and December 31, 2016 , none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Preferred Distribution Rate Reset Election A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a Rate Reset Election to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points ; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. The Rate Reset Election of the preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other Expense in our Consolidated Statement of Operations. At December 31, 2017, the fair value of this embedded derivative was a liability of $45.2 million . See Note 11 for additional information regarding our Class A convertible preferred units and the Rate Reset Election. Effect on Operating Results Amount of Gain (Loss) Recognized in Income Year Ended Consolidated Statements of Operations Location 2017 2016 2015 Commodity derivatives—futures and call options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ 5,116 $ (13,195 ) $ (1,101 ) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs (1,314 ) (5,847 ) 16,026 Total commodity derivatives $ 3,802 $ (19,042 ) $ 14,925 Preferred Distribution Rate Reset Election ( Note 19 ) Other Expense $ (10,472 ) $ — $ — We have no derivative contracts with credit contingent features.

Fair-Value Measurements

Fair-Value Measurements	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 . December 31, 2017 December 31, 2016 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 559 $ — $ — $ 3,764 $ — $ — Liabilities $ (2,066 ) $ — $ — $ (11,278 ) $ — $ — Preferred Distribution Rate Reset Election $ — $ — $ (45,209 ) $ — $ — $ — Rollforward of Level 3 Fair Value Measurements The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3: Year Ended December 31, 2017 Beginning Balance — Initial valuation of Preferred Distribution Rate Reset Election $ (34,450 ) Net Loss for the period included in earnings (10,472 ) Allocation of Distribution Paid-in-kind (287 ) Ending Balance $ (45,209 ) 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 embedded derivative feature is based on a valuation model that estimates the fair value of the convertible preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit price, a ten year history of the dividend yield, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as Other income (expense), net. See Note 18 for additional information on our derivative instruments. Nonfinancial Assets and Liabilities We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such assets within our Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3. Other Fair Value Measurements We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At December 31, 2017 our senior unsecured notes had a carrying value of $2.6 billion and a fair value of $2.7 billion , compared to $1.8 billion and $1.9 billion , respectively at December 31, 2016 . 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. Additionally, we recorded the fair value of net assets acquired and liabilities assumed in connection with our Alkali Business acquisition as of the acquisition date of September 1, 2017. The fair value measurements were primarily based on significant unobservable inputs (Level 3) developed using company-specific information. See Note 3 for further information associated with the values recorded in our Alkali Business acquisition.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans Upon acquisition of our Alkali Business in 2017, we now sponsor a defined benefit plan. We account for the Alkali Business benefit plan as a single employer pension plan that benefits only employees of our Alkali Business, and thus, the related assets and liability costs of the plan are recorded in the Consolidated Balance Sheet. Under the Alkali Business benefit plan, each eligible employee will automatically become a participant upon completion of one year of credited service. Retirement benefits under this plan are calculated based on the total years of service of an eligible participant, multiplied by a specified benefit rate in effect at the termination of the plan participant's years of service. The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2017 Change in benefit obligation: Benefit Obligation, beginning of year $ — Service Cost 1,749 Interest Cost 267 Actuarial Loss 992 Benefits Paid (56 ) Acquisition of Alkali Business 19,578 Benefit Obligation, end of year 22,530 Change in plan assets: Fair Value of Plan Assets, beginning of year — Actual Return on Plan Assets 647 Employer Contributions 2,250 Benefits Paid (56 ) Acquisition of Alkali Business 10,465 Fair Value of Plan assets, end of year 13,306 Funded Status at end of period $ (9,224 ) Amounts recognized in the Statement of Financial Position Non-current assets $ — Current liabilities — Non-current Liabilities (9,224 ) Net Asset (Liability) at end of year $ (9,224 ) Amounts recognized in accumulated other comprehensive loss: Net actuarial loss 604 Amounts recognized in accumulated other comprehensive loss: $ 604 Estimated Future Cash Flows- The following employer contributions and benefit payments, which reflect expected future service, are expected to be paid as follows: Employer Contributions Expected 2018 Contributions by Employer $ 3,898 Future Expected Benefit Payments 2018 $ 413 2019 676 2020 869 2021 983 2022 1,099 2023-2027 7,672 Net Periodic Pension Costs- The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2017 Service Cost $ 1,749 Interest Cost 267 Expected Return on Assets (259 ) $ 1,757 Significant Assumptions- Discount rates are determined annually and are based on rates of return of high-quality long-term fixed income securities currently available and expected to be available during the maturity of the pension benefits. The long-term rate of return estimation for the Alkali benefit plan is based on a capital asset pricing model using historical data and a forecasted earnings model. An expected return on plan assets analysis is performed which incorporates the current portfolio allocation, historical asset-class returns and an assessment of expected future performance using asset-class risk factors. The Alkali Business benefit plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan's management. The committee is responsible for the oversight and management of the plan's investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2017 Discount Rate 3.90 % Expected Long-term Rate of Return 6.28 % Rate of Compensation Increase N/A The discount rate used to determine the net periodic cost at the beginning of the period was 4.15% . Pension Plan Assets - We maintain target allocation percentages among various asset classes based on an investment policy established for our Pension Plan. The target allocation is designed to achieve long term objectives of return, mitigating risk, and considering expected cash flows. Our Pension Plan asset allocations at December 31, 2017 by asset category are as follows: December 31, 2017 Target % Actual % Equity securities 41-60% 41 % Fixed income securities 40-50% 50 % Other 0-10% 9 % A summary of total investments for our pension plan assets measured at fair value at December 31, 2017 is presented below: December 31, 2017 Level 1 Level 2 Level 3 Total Cash and cash equivalents 260 — — 260 Equity securities 2,518 — — 2,518 Mutual and other exchange traded funds 10,528 — — 10,528 13,306 — — 13,306

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments and Guarantees Our office lease for our corporate headquarters extends until October 31, 2022 . To transport products, we lease tractors, trailers and railcars. In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS and caustic soda. Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput. We have no minimum volumetric or financial requirements remaining on our pipeline lease. The future minimum rental payments under all non-cancelable operating leases as of December 31, 2017 , were as follows (in thousands): Office Space Transportation Equipment Terminals and Tanks Total 2018 $ 3,972 $ 25,871 $ 14,737 $ 44,580 2019 3,951 25,209 12,593 41,753 2020 3,984 23,403 8,833 36,220 2021 3,233 17,818 6,545 27,596 2022 2,693 16,317 4,754 23,764 2023 and thereafter 4,696 55,614 55,627 115,937 Total minimum lease obligations $ 22,529 $ 164,232 $ 103,089 $ 289,850 Total operating lease expense from our continuing operations was as follows (in thousands): Year Ended December 31, 2017 $ 36,933 Year Ended December 31, 2016 $ 41,906 Year Ended December 31, 2015 $ 36,833 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, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the federal income tax returns of each of our partners. A few of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay federal and state income taxes on these operations. The Tax Cuts and Jobs Act (“Act”) was enacted on December 22, 2017. The Act contains several tax law changes that will impact the Partnership in the current and future periods, including a reduction in the U.S. federal corporate tax rate from 35% to 21% . At December 31, 2017 , the Partnership has not completed its accounting for the tax effects of the Act; however, in certain cases, as described below, the Partnership has made a reasonable estimate of the effects on our existing deferred tax balances. The Partnership remeasured its U.S. deferred tax assets and liabilities and recorded a $5.3 million benefit relating to the U.S. federal corporate tax rate change. Our income tax (benefit) expense is as follows: Year Ended December 31, 2017 2016 2015 Current: Federal $ — $ — $ — State 100 1,200 1,200 Total current income tax expense (benefit) $ 100 $ 1,200 $ 1,200 Deferred: Federal $ (5,530 ) $ 1,862 $ 2,478 State 1,471 280 309 Total deferred income tax expense (benefit) $ (4,059 ) $ 2,142 $ 2,787 Total income tax expense (benefit) $ (3,959 ) $ 3,342 $ 3,987 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, 2017 2016 Deferred tax assets: Net operating loss carryforwards $ 9,506 $ 10,787 Total long-term deferred tax asset 9,506 10,787 Valuation allowances (1,285 ) (869 ) Total deferred tax assets $ 8,221 $ 9,918 Deferred tax liabilities: Long-term: Fixed assets $ (3,896 ) $ (4,480 ) Intangible assets (15,797 ) (20,693 ) Other (441 ) (716 ) Total long-term liability (20,134 ) (25,889 ) Total deferred tax liabilities $ (20,134 ) $ (25,889 ) Total net deferred tax liability $ (11,913 ) $ (15,971 ) 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, 2017 2016 2015 Income from operations before income taxes $ 78,120 $ 114,424 $ 425,572 Partnership income not subject to federal income tax (77,704 ) (109,111 ) (418,500 ) Income subject to federal income taxes $ 416 $ 5,313 $ 7,072 Tax expense at federal statutory rate $ 146 $ 1,860 $ 2,475 State income taxes, net of federal tax 1,396 949 928 Return to provision, federal and state (163 ) (198 ) (193 ) Other (68 ) 731 777 Remeasurement of deferred taxes due to enacted tax rate change (5,270 ) — — Income tax expense (benefit) $ (3,959 ) $ 3,342 $ 3,987 Effective tax rate on income from operations before income taxes (5 )% 3 % 1 % At December 31, 2017 , 2016 and 2015, we had no uncertain tax positions.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Quarterly Financial Information (Unaudited)	Quarterly Financial Data (Unaudited) The table below summarizes our unaudited quarterly financial data for 2017 and 2016 . 2017 Quarters First Second Third Fourth Revenues from continuing operations $ 415,491 $ 406,723 $ 486,114 $ 720,049 Operating income $ 52,597 $ 61,447 $ 43,100 $ 63,407 Net income $ 26,938 $ 33,580 $ 6,160 $ 15,401 Net loss attributable to noncontrolling interest $ 152 $ 153 $ 152 $ 111 Net income attributable to Genesis Energy, L.P. $ 27,090 $ 33,733 $ 6,312 $ 15,512 Basic and diluted net income per common unit: Net income per common unit $ 0.23 $ 0.28 $ 0.01 $ (0.01 ) Cash distributions per common unit (1) $ 0.7100 $ 0.7200 $ 0.7225 $ 0.5000 2016 Quarters First Second Third Fourth Revenues from continuing operations $ 378,414 $ 445,976 $ 460,050 $ 428,053 Operating income $ 59,848 $ 47,988 $ 55,179 $ 43,412 Net income $ 35,177 $ 23,601 $ 31,983 $ 20,321 Net loss (income) attributable to noncontrolling interest $ 126 $ 126 $ 118 $ 1,797 Net income attributable to Genesis Energy, L.P. $ 35,303 $ 23,727 $ 32,101 $ 22,118 Basic and diluted net income per common unit: Net income per common unit $ 0.32 $ 0.22 $ 0.28 $ 0.19 Cash distributions per common unit (1) $ 0.6550 $ 0.6725 $ 0.6900 $ 0.7000 (1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information Disclosure	Condensed Consolidating Financial Information Our $2.6 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 10 for additional information regarding our consolidated debt obligations. The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors: Condensed Consolidating Balance Sheet December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 8,340 $ 695 $ — $ 9,041 Other current assets 50 — 614,682 12,316 (56 ) 626,992 Total current assets 56 — 623,022 13,011 (56 ) 636,033 Fixed Assets, at cost — — 5,523,431 77,584 — 5,601,015 Less: Accumulated depreciation — — (708,269 ) (26,717 ) — (734,986 ) Net fixed assets — — 4,815,162 50,867 — 4,866,029 Mineral Leaseholds — — 564,506 — — 564,506 Goodwill — — 325,046 — — 325,046 Other assets, net 14,083 — 378,371 126,300 (154,437 ) 364,317 Advances to affiliates 3,808,712 — — 85,423 (3,894,135 ) — Equity investees and other investments — — 381,550 — — 381,550 Investments in subsidiaries 2,689,861 — 82,616 — (2,772,477 ) — Total assets $ 6,512,712 $ — $ 7,170,273 $ 275,601 $ (6,821,105 ) $ 7,137,481 LIABILITIES AND CAPITAL Current liabilities $ 46,086 $ — $ 399,017 $ 11,417 $ (256 ) $ 456,264 Senior secured credit facilities 1,099,200 — — — — 1,099,200 Senior unsecured notes 2,598,918 — — — — 2,598,918 Deferred tax liabilities — — 11,913 — — 11,913 Advances from affiliates — — 3,894,027 — (3,894,027 ) — Other liabilities 45,210 — 182,414 183,237 (154,290 ) 256,571 Total liabilities 3,789,414 — 4,487,371 194,654 (4,048,573 ) 4,422,866 Mezzanine Capital: Class A Convertible Preferred Units 697,151 — — — — 697,151 Partners’ capital, common units 2,026,147 — 2,683,506 89,026 (2,772,532 ) 2,026,147 Accumulated other comprehensive income (loss) (1) — — (604 ) — — (604 ) Noncontrolling interests — — — (8,079 ) — (8,079 ) Total liabilities, mezzanine capital and partners’ capital $ 6,512,712 $ — $ 7,170,273 $ 275,601 $ (6,821,105 ) $ 7,137,481 (1) The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our Guarantor Subsidiaries. Condensed Consolidating Balance Sheet December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 6,360 $ 663 $ — $ 7,029 Other current assets 50 — 340,555 12,237 (302 ) 352,540 Total current assets 56 — 346,915 12,900 (302 ) 359,569 Fixed Assets, at cost — — 4,685,811 77,585 — 4,763,396 Less: Accumulated depreciation — — (524,315 ) (24,217 ) — (548,532 ) Net fixed assets — — 4,161,496 53,368 — 4,214,864 Mineral Leaseholds — — — — — — Goodwill — — 325,046 — — 325,046 Other assets, net 10,696 — 390,214 133,980 (140,533 ) 394,357 Advances to affiliates 2,650,930 — — 73,295 (2,724,225 ) — Equity investees and other investments — — 408,756 — — 408,756 Investments in subsidiaries 2,594,882 — 80,735 — (2,675,617 ) — Total assets $ 5,256,564 $ — $ 5,713,162 $ 273,543 $ (5,540,677 ) $ 5,702,592 LIABILITIES AND CAPITAL Current liabilities $ 34,864 $ — $ 211,591 $ 14,505 $ (157 ) $ 260,803 Senior secured credit facilities 1,278,200 — — — — 1,278,200 Senior unsecured notes 1,813,169 — — — — 1,813,169 Deferred tax liabilities — — 25,889 — — 25,889 Advances from affiliates — — 2,724,224 — (2,724,224 ) — Other liabilities — — 165,266 179,592 (140,377 ) 204,481 Total liabilities 3,126,233 — 3,126,970 194,097 (2,864,758 ) 3,582,542 Mezzanine Capital Class A Convertible Preferred Units — — — — — — Partners' capital 2,130,331 — 2,586,192 89,727 (2,675,919 ) 2,130,331 Accumulated other comprehensive income (loss) — — — — — — Noncontrolling interests — — — (10,281 ) — (10,281 ) Total liabilities, mezzanine capital and partners’ capital $ 5,256,564 $ — $ 5,713,162 $ 273,543 $ (5,540,677 ) $ 5,702,592 Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 318,239 $ — $ — $ 318,239 Sodium minerals and sulfur services — — 460,790 9,252 (7,420 ) 462,622 Marine transportation — — 205,287 — — 205,287 Onshore facilities and transportation — — 1,023,293 18,936 — 1,042,229 Total revenues — — 2,007,609 28,188 (7,420 ) 2,028,377 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 967,558 1,089 — 968,647 Marine transportation costs — — 154,606 — — 154,606 Sodium minerals and sulfur services operating costs — — 332,209 9,129 (7,420 ) 333,918 Offshore pipeline transportation operating costs — — 69,225 2,840 — 72,065 General and administrative — — 66,421 — — 66,421 Depreciation and amortization — — 249,980 2,500 — 252,480 Gain on sale of assets — — (40,311 ) — — (40,311 ) Total costs and expenses — — 1,799,688 15,558 (7,420 ) 1,807,826 OPERATING INCOME — — 207,921 12,630 — 220,551 Equity in earnings of equity investees — — 51,046 — — 51,046 Equity in earnings of subsidiaries 276,341 — (520 ) — (275,821 ) — Interest (expense) income, net (176,979 ) — 14,122 (13,905 ) — (176,762 ) Other expense (16,715 ) — — — — (16,715 ) Income before income taxes 82,647 — 272,569 (1,275 ) (275,821 ) 78,120 Income tax benefit (expense) — — 3,928 31 — 3,959 NET INCOME 82,647 — 276,497 (1,244 ) (275,821 ) 82,079 Net loss attributable to noncontrolling interests — — — 568 — 568 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 82,647 $ — $ 276,497 $ (676 ) $ (275,821 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (21,995 ) — — — — (21,995 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 60,652 $ — $ 276,497 $ (676 ) $ (275,821 ) $ 60,652 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 334,679 $ — $ 334,679 Sodium minerals and sulfur services — — 171,389 7,873 (7,759 ) 171,503 Marine transportation — — 213,021 — — 213,021 Onshore facilities and transportation — — 972,794 20,496 — 993,290 Total revenues — — 1,691,883 28,369 (7,759 ) 1,712,493 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 923,567 1,060 — 924,627 Marine transportation costs — — 142,551 — — 142,551 Sodium minerals and sulfur services operating costs — — 90,711 8,491 (7,759 ) 91,443 Offshore pipeline transportation operating costs — — 68,791 10,833 — 79,624 General and administrative — — 45,625 — — 45,625 Depreciation and amortization — — 219,696 2,500 — 222,196 Total costs and expenses — — 1,490,941 22,884 (7,759 ) 1,506,066 OPERATING INCOME — — 200,942 5,485 — 206,427 Equity in earnings of equity investees — — 47,944 — — 47,944 Equity in earnings of subsidiaries 253,048 — (6,744 ) — (246,304 ) — Interest (expense) income, net (139,799 ) — 14,407 (14,555 ) — (139,947 ) Other expense, net — — — — — — Income before income taxes 113,249 — 256,549 (9,070 ) (246,304 ) 114,424 Income tax expense — — (3,337 ) (5 ) — (3,342 ) NET INCOME 113,249 — 253,212 (9,075 ) (246,304 ) 111,082 Net loss attributable to noncontrolling interests — — — 2,167 — 2,167 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units — — — — — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 137,681 $ 2,549 $ — $ 140,230 Sodium minerals and sulfur services — — 175,132 11,942 (9,194 ) 177,880 Marine transportation — — 238,757 — — 238,757 Onshore facilities and transportation — — 1,665,917 23,745 — 1,689,662 Total revenues — — 2,217,487 38,236 (9,194 ) 2,246,529 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 1,601,972 836 — 1,602,808 Marine transportation costs — — 135,200 — — 135,200 Sodium minerals and sulfur services operating costs — — 94,241 11,759 (9,194 ) 96,806 Offshore pipeline transportation operating costs — — 38,459 1,254 — 39,713 General and administrative — — 64,995 — — 64,995 Depreciation and amortization — — 141,785 8,355 — 150,140 Total costs and expenses — — 2,076,652 22,204 (9,194 ) 2,089,662 OPERATING INCOME — — 140,835 16,032 — 156,867 Equity in earnings of equity investees — — 54,450 — — 54,450 Equity in earnings of subsidiaries 542,226 — 2,053 — (544,279 ) — Gain on basis step up on historical interest — — 332,380 — — 332,380 Interest (expense) income, net (100,494 ) — 15,042 (15,144 ) — (100,596 ) Other income/(expense), net (19,204 ) — 1,675 — — (17,529 ) Income before income taxes 422,528 — 546,435 888 (544,279 ) 425,572 Income tax expense — — (4,036 ) 49 — (3,987 ) NET INCOME $ 422,528 $ — $ 542,399 $ 937 $ (544,279 ) $ 421,585 Net loss attributable to noncontrolling interest $ — $ — $ — $ 943 $ — 943 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 422,528 $ — $ 542,399 $ 1,880 $ (544,279 ) $ 422,528 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ — $ — $ — $ — $ — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 422,528 $ — $ 542,399 $ 1,880 $ (544,279 ) $ 422,528 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 162,980 $ — $ 481,727 $ (4,585 ) $ (301,264 ) $ 338,858 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (250,593 ) — — (250,593 ) Cash distributions received from equity investees - return of investment — — 20,280 — — 20,280 Investments in equity investees (140,513 ) — (4,647 ) — 140,513 (4,647 ) Acquisitions — — (1,325,759 ) — — (1,325,759 ) Intercompany transfers (1,157,781 ) — — — 1,157,781 — Repayments on loan to non-guarantor subsidiary — — 6,764 — (6,764 ) — Contributions in aid of construction costs — — 124 — — 124 Proceeds from asset sales — — 85,722 — — 85,722 Other, net — — — — — — Net cash (used in) provided by investing activities (1,298,294 ) — (1,468,109 ) — 1,291,530 (1,474,873 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,458,700 — — — — 1,458,700 Repayments on senior secured credit facility (1,637,700 ) — — — — (1,637,700 ) Proceeds from issuance of senior unsecured notes, including premium 1,000,000 — — — — 1,000,000 Proceeds from issuance of Class A convertible preferred units, net 726,419 — — — — 726,419 Repayment of senior unsecured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Intercompany transfers — — 1,169,781 (12,000 ) (1,157,781 ) — Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Distributions to partners/owners (321,875 ) — (321,875 ) — 321,875 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 Other, net — — (57 ) 13,847 (13,847 ) (57 ) Net cash provided by financing activities 1,135,314 — 988,362 4,617 (990,266 ) 1,138,027 Net decrease in cash and cash equivalents — — 1,980 32 — 2,012 Cash and cash equivalents at beginning of period 6 — 6,360 663 — 7,029 Cash and cash equivalents at end of period $ 6 $ — $ 8,340 $ 695 $ — $ 9,041 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 179,853 $ — $ 398,320 $ 9,586 $ (289,421 ) $ 298,338 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (463,100 ) — — (463,100 ) Cash distributions received from equity investees - return of investment — — 21,353 — — 21,353 Investments in equity investees (298,020 ) — — — 298,020 — Acquisitions — — (25,394 ) — — (25,394 ) Intercompany transfers (31,436 ) — — — 31,436 — Repayments on loan to non-guarantor subsidiary — — 6,113 — (6,113 ) — Contributions in aid of construction costs — — 13,374 — — 13,374 Proceeds from assets sales — — 3,609 — — 3,609 Other, net — — (151 ) — — (151 ) Net cash (used in) provided by investing activities (329,456 ) — (444,196 ) — 323,343 (450,309 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,115,800 — — — — 1,115,800 Repayments on senior secured credit facility (952,600 ) — — — — (952,600 ) Debt issuance costs (1,578 ) — — — — (1,578 ) Intercompany transfers — — 57,701 (26,264 ) (31,437 ) — Issuance of common units for cash, net 298,020 — 298,020 — (298,020 ) 298,020 Distributions to partners/owners (310,039 ) — (310,039 ) — 310,039 (310,039 ) Contributions from noncontrolling interest — — — 236 — 236 Other, net — — (1,734 ) 14,504 (14,504 ) (1,734 ) Net cash provided by (used in) financing activities 149,603 — 43,948 (11,524 ) (33,922 ) 148,105 Net increase (decrease) in cash and cash equivalents — — (1,928 ) (1,938 ) — (3,866 ) Cash and cash equivalents at beginning of period 6 — 8,288 2,601 — 10,895 Cash and cash equivalents at end of period $ 6 $ — $ 6,360 $ 663 $ — $ 7,029 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ (14,082 ) $ — $ 308,144 $ 45,125 $ (49,651 ) $ 289,536 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (495,774 ) — — (495,774 ) Cash distributions received from equity investees - return of investment 186,026 — 25,645 — (186,026 ) 25,645 Investments in equity investees (633,761 ) — (3,045 ) — 633,761 (3,045 ) Acquisitions — — (1,520,299 ) — — (1,520,299 ) Intercompany transfers (1,240,973 ) — — — 1,240,973 — Repayments on loan to non-guarantor subsidiary — — 5,524 — (5,524 ) — Contributions in aid of construction costs — — 3,179 — — 3,179 Proceeds from asset sales — — 2,811 — — 2,811 Other, net — — (1,976 ) — — (1,976 ) Net cash (used in) provided by investing activities (1,688,708 ) — (1,983,935 ) — 1,683,184 (1,989,459 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,525,050 — — — — 1,525,050 Repayments on senior secured credit facility (960,450 ) — — — — (960,450 ) Proceeds from issuance of senior unsecured notes 1,139,718 — — — — 1,139,718 Repayment of senior secured notes (350,000 ) — — — — (350,000 ) Debt issuance costs (28,901 ) — — — — (28,901 ) Distribution to partners/owners (256,389 ) — (256,389 ) — 256,389 (256,389 ) Distributions to noncontrolling interest — — (960 ) — — (960 ) Issuance of common units for cash, net 633,759 — 633,759 — (633,759 ) 633,759 Intercompany transfers — — 1,299,830 (58,857 ) (1,240,973 ) — Other, net — — (471 ) 15,190 (15,190 ) (471 ) Net cash provided by (used in) financing activities 1,702,787 — 1,675,769 (43,667 ) (1,633,533 ) 1,701,356 Net increase (decrease) in cash and cash equivalents (3 ) — (22 ) 1,458 — 1,433 Cash and cash equivalents at beginning of period 9 — 8,310 1,143 — 9,462 Cash and cash equivalents at end of period $ 6 $ — $ 8,288 $ 2,601 $ — $ 10,895

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events In January 2018, we called for redemption of the remaining $145.2 million of the original $350 million aggregate principal amount of our outstanding 5.750% senior notes due 2021. The redemption was completed on February 15, 2018 and holders received a redemption price of 101.438% of the principal amount, plus accrued and unpaid interest.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 and our results of operations, statements of comprehensive income, changes in partners’ capital and cash flows for the years ended December 31, 2017 , 2016 and 2015 . 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 a 64% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon"), a 25.7% interest in Neptune Pipeline Company, LLC and a 29% interest in Odyssey Pipeline L.L.C. (or "Odyssey"). We account for our investments in these joint ventures by the equity method of accounting.
Use of Estimates	Use of Estimates The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding expected forfeiture rates of the rights and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We have no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.
Accounts Receivable	Accounts Receivable We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.
Inventories	Inventories Our inventories are valued at the lower of cost or net realizable value. With the exception of our Alkali Business, cost is determined principally under the average cost method within specific inventory pools.
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, 5 to 30 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 10 years for buildings and improvements, office equipment, furniture and fixtures and other equipment. Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost. Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Mineral leaseholds are depleted over their useful lives as determined under the units of production method. When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, the costs incurred to develop such property through the commencement of production are capitalized.
Deferred Charges on Marine Transportation Assets	Deferred Charges on Marine Transportation Assets Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years. The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last.
Asset Retirement Obligations	Asset Retirement Obligations Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our asset retirement obligations relate to future costs associated with the disconnecting or removing of our crude oil and natural gas pipelines and platforms, CO 2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. Accretion of the discount increases the liability and is recorded to expense.
Direct Financing Leasing Arrangements	Direct Financing Leasing Arrangements For our direct financing leases, we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in onshore facilities and transportation revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets. We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit rating and financial position of the lessee.
Intangible and Other Assets	Intangible and Other Assets Intangible assets with finite useful lives are amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We are amortizing our customer and supplier relationships, contract agreements, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are being amortized on a straight-line basis. We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented. Costs incurred in connection with the issuance of long-term debt and certain amendments to our credit facilities have historically been capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Certain of our capitalized debt issuance costs related to our respective issuances of notes are classified as reductions in long-term debt.
Goodwill	Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During the evaluation, we may perform a qualitative assessment of relevant events and circumstances to determine the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. We may also elect to exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. If the calculated fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings may be necessary to reduce the carrying value of the goodwill to its implied fair value. In the event that we determine that goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made. No goodwill impairment has occurred in any of the periods presented.
Environmental Liabilities	Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
Equity-Based Compensation	Equity-Based Compensation Our phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or directors of our general partner upon exercise or vesting of the related award. The fair value of our phantom units is equal to the market price of our common units. Our phantom units include both service-based and performance-based awards. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award.
Revenue Recognition	Revenue Recognition Offshore Pipeline Transportation—Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenues from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenues from offshore platform services are recognized in the period the services are provided. Revenue from commodity charges is based on a fee per unit of volume (typically per MMcf of natural gas or per barrel of crude oil) delivered to the platform multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers. Product Sales—Revenues from the sale of crude oil, petroleum products and CO 2 by our onshore facilities and transportation segment, and caustic soda, NaHS, soda ash and other alkali products by our sodium minerals and sulfur services segment are recognized when title to the inventory is transferred to the customer, pricing is fixed and determinable, collectability is reasonably assured and there are no further significant obligations for future performance by us. Most frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although in certain situations, title transfers when the inventory is loaded for transportation to the customer. Our crude oil and petroleum products are typically sold at prices based off daily or monthly published prices. Many of our contracts for sales of NaHS incorporate the price of caustic soda in the pricing formulas. When necessary, accruals are made for sales returns, rebates and other allowances. Rail Facility Loading and Unloading Revenues—Revenues based on a per barrel fee from the loading and/or unloading of crude oil at our rail facilities is recognized as the crude oil enters or exits the railcars. Onshore Pipeline Transportation—Revenues from transportation of crude oil by our pipelines are based on actual volumes at a published tariff. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to the specifications outlined in our regulated tariffs. Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline revenues. In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines (onshore and offshore) due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs and agreements include the right for us to make volumetric deductions from the shippers for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances. 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, based on prevailing market prices at that time. 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 that we must make to replace the lost volumes. We reflect inventories in the Consolidated Financial Statements at the lower of the recorded value or the market value at the balance sheet date. We value liabilities to replace crude oil at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value.
Cost of Sales and Operating Expenses	Cost of Sales and Operating Expenses Onshore facilities and transportation operating costs include the cost to acquire the product and the associated costs to transport it to our terminal facilities, including storing, or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars, terminals, barges and other vessels , including personnel costs, fuel and maintenance of our or third-party owned equipment. Additionally, costs to operate and maintain the integrity of our onshore pipelines are included herein. When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as onshore facilities and transportation revenues. Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are often rebillable and passed through to the customer. The most significant operating costs in our sodium minerals and sulfur services segment consist of the costs to operate our trona extraction and soda ash processing facilities, NaHS plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas, and costs to transport the soda ash, other alkali products, NaHS and caustic soda. Pipeline operating costs consist primarily of power costs to operate pumping and platform equipment, personnel costs to operate the pipelines and platforms, insurance costs and costs associated with maintaining the integrity of our pipelines.
Income Taxes	Income Taxes We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner. Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. In addition, we have determined that certain provisions in our Class A Convertible Preferred units represent an embedded derivative which must be bifurcated and recorded at fair value, with changes in fair value in respective periods being recorded in our Consolidated Statements of Operations.
Fair Value of Current Assets and Current Liabilities	Fair Value of Current Assets and Current Liabilities The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature.
Pension Benefits	Pension benefits As a result of our acquisition of our Alkali Business, we now sponsor a defined benefit plan. The defined benefit plan is accounted for using actuarial valuations as required by GAAP. We recognize the funded status of the defined pension plan on the balance sheet and recognize changes in the funded status that arise during the period but are not recognized as components of net periodic benefit cost within other comprehensive income or loss
Business Acquisitions	Business Acquisitions 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.
Recent and Proposed Accounting Pronouncements	Recent and Proposed Accounting Pronouncements In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective transition method. In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved early adoption of the standard, but not before the original effective date of December 15, 2016. As a result of our process of evaluating the impact of this guidance on each type of revenue contract entered into with customers, we have determined that the adoption of this guidance will have an immaterial impact on revenues and costs in certain of our revenue streams including our legacy sulfur removal operations relating to our NaHS business. We expect these items to have an even less significant impact on net income on a go forward basis. We have also identified certain contracts or elements of contracts for product loss allowances and tiered pricing that will be impacted. These items will not have a material impact on our financial statements. We are adopting this guidance by using the modified retrospective approach, effective January 1, 2018, by recognizing the cumulative effect of applying the guidance for periods prior to January 1, 2018 to the opening balance of Partner’s Capital. Management has concluded the estimated cumulative effect to be recorded is not material. In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost and net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements. In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this guidance. In August 2016, the FASB issued guidance that addresses how certain cash receipts and payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We expect this guidance to have an impact on how we report our operating and investing cash flows from certain cash receipts and payments, particularly relating to cash distributions received from certain of our equity investees. In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019. We adopted this guidance and it did not have an impact on our consolidated financial statements.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Alkali Business [Member]
Business Acquisition [Line Items]
Schedule of Purchase Price Allocation	The preliminary allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Accounts receivable 138,258 Inventories 34,929 Other current assets 13,254 Fixed assets 663,217 Mineral leaseholds 566,019 Intangible assets 800 Other assets 3,612 Accounts payable (44,547 ) Accrued Liabilities (36,884 ) Other long-term liabilities (13,658 ) Total Purchase Price $ 1,325,000
Selected Financial Information	The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Year Ended 2017 Revenues 277,011 Net income 42,014
Schedule of Pro Forma Financial Information	The dilutive effect of Class A Preferred Units is calculated using the if-converted method. Year Ended 2017 2016 2015 Pro forma consolidated financial operating results: Revenues $ 2,549,438 $ 2,498,293 $ 3,043,529 Net Income Attributable to Genesis Energy, L.P. 84,010 120,515 416,118 Net Income Available to Common Unitholders 18,953 57,057 351,436 Basic and diluted earnings per common unit: As reported net income per common unit $ 0.50 $ 1.00 $ 4.10 Pro forma net income per common unit, basic $ 0.16 $ 0.50 $ 3.41 Pro forma net income per common unit, dilutive $ 0.16 $ 0.50 $ 3.33
Enterprise Offshore Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Purchase Price Allocation	The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows: Cash $ 1,270 Accounts receivable 29,768 Inventories 600 Other current assets 10,432 Fixed assets 1,225,685 Intangible assets 79,050 Equity investees 352,535 Other assets 1,966 Accounts payable (6,110 ) Accrued liabilities (18,662 ) Other long-term liabilities (161,412 ) Noncontrolling interest 6,447 Total purchase price $ 1,521,569
Selected Financial Information	The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented: Year Ended 2015 Revenues $ 101,444 Net income $ 58,805
Schedule of Pro Forma Financial Information	The table below presents selected unaudited pro forma financial information incorporating the historical results of our newly acquired offshore pipeline transportation assets. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2015 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of the Enterprise offshore pipelines and services businesses and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Enterprise acquisition been completed on January 1, 2015. Year Ended Pro forma consolidated financial operating results: 2015 Revenues $ 2,421,989 Net Income Attributable to Genesis Energy L.P. $ 425,363 Basic and diluted earnings per unit: As reported net income per unit $ 4.09 Pro forma net income per unit $ 3.91

Receivables (Tables)

Receivables (Tables)	12 Months Ended
	Dec. 31, 2017
Accounts Receivable, Net, Current [Abstract]
Schedule Of Trade Accounts Receivables Net	Accounts receivable – trade, net consisted of the following: December 31, 2017 2016 Accounts receivable - trade $ 503,917 $ 231,187 Allowance for doubtful accounts (8,468 ) (6,505 ) Accounts receivable - trade, net $ 495,449 $ 224,682
Schedule Of Allowance For Doubtful Accounts	The following table presents the activity of our allowance for doubtful accounts for the periods indicated: December 31, 2017 2016 2015 Balance at beginning of period $ 6,505 $ 1,446 $ 2,973 Charged to costs and expenses 2,001 6,463 1,242 Amounts written off (38 ) (1,404 ) (2,769 ) Balance at end of period $ 8,468 $ 6,505 $ 1,446

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Schedule Of Major Components Of Inventories	The major components of inventories were as follows: December 31, 2017 2016 Petroleum products $ 8,731 $ 11,550 Crude oil 29,873 73,133 Caustic soda 5,755 4,593 NaHS 8,277 9,304 Raw materials - Alkali Operations 4,550 — Work-in-process - Alkali Operations 7,355 — Finished goods, net - Alkali Operations 14,075 — Materials and supplies, net - Alkali Operations 10,030 — Other 7 7 Total $ 88,653 $ 98,587

Fixed Assets and Asset Retire37

Fixed Assets and Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Fixed Assets And Asset Retirement Obligations [Abstract]
Schedule of Fixed Assets	Fixed assets consisted of the following: December 31, 2017 2016 Crude oil pipelines and natural gas pipelines and related assets $ 3,028,657 $ 2,901,202 Alkali facilities, machinery, and equipment 497,601 — Onshore facilities, machinery, and equipment 692,364 427,658 Transportation equipment 21,483 17,543 Marine vessels 918,953 863,199 Land, buildings and improvements 223,186 55,712 Office equipment, furniture and fixtures 18,112 9,654 Construction in progress 151,768 440,225 Other 48,891 48,203 Fixed assets, at cost 5,601,015 4,763,396 Less: Accumulated depreciation (734,986 ) (548,532 ) Net fixed assets $ 4,866,029 $ 4,214,864
Schedule of Mineral Leaseholds	Mineral Leaseholds Our Mineral Leaseholds, as relating to our recently acquired Alkali Business, consist of the following: December 31, Mineral leaseholds 566,019 Less: Accumulated depletion (1,513 ) Mineral leaseholds, net $ 564,506
Schedule of Change in Asset Retirement Obligation	A reconciliation of our liability for asset retirement obligations is as follows: December 31, 2015 $ 188,662 AROs arising from the acquisition and consolidation of a previously held equity method investment 20,940 Accretion expense 10,800 Revisions in timing and estimated costs of AROs (2,254 ) Settlements (4,422 ) December 31, 2016 213,726 Accretion expense 11,008 Revisions in timing and estimated costs of AROs 7,146 Acquisitions 131 Divestitures (7,649 ) Settlements (26,415 ) Other 240 December 31, 2017 $ 198,187
Schedule of Asset Retirement Obligations	With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated: 2018 $ 10,799 2019 $ 9,760 2020 $ 9,429 2021 $ 10,069 2022 $ 10,753

Net Investment in Direct Fina38

Net Investment in Direct Financing Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Components Of Net Investment In Direct Financing Leases	The following table lists the components of the net investment in direct financing leases: December 31, 2017 2016 Total minimum lease payments to be received $ 215,884 $ 236,495 Unamortized initial direct costs 950 1,107 Less unearned income (83,918 ) (97,822 ) Net investment in direct financing leases 132,916 139,780 Less current portion (included in other current assets) (7,633 ) (6,921 ) Long-term portion of net investment in direct financing leases $ 125,283 $ 132,859

Equity Investees (Tables)

Equity Investees (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
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, 2017 2016 2015 Genesis’ share of operating earnings $ 66,814 $ 63,805 $ 17,157 Amortization of differences attributable to Genesis' carrying value of equity investments (15,768 ) (15,861 ) 37,293 Net equity in earnings $ 51,046 $ 47,944 $ 54,450 Distributions received $ 82,898 $ 87,220 $ 97,468
Schedule of Balance Sheet Information For Equity Investees	The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis) including the effects of the change in our ownership interest due to the Enterprise and Deepwater acquisitions as previously discussed: December 31, 2017 2016 BALANCE SHEET DATA: Assets Current assets $ 34,381 $ 35,375 Fixed assets, net 362,214 365,563 Other assets 14,927 3,177 Total assets $ 411,522 $ 404,115 Liabilities and equity Current liabilities $ 23,289 $ 23,928 Other liabilities 249,610 230,327 Equity 138,623 149,860 Total liabilities and equity $ 411,522 $ 404,115
Schedule of Operations For Equity Investees	Year Ended December 31, 2017 2016 2015 INCOME STATEMENT DATA: Revenues $ 191,078 $ 193,038 $ 189,941 Operating Income $ 139,604 $ 122,836 $ 12,191 Net Income $ 134,479 $ 118,175 $ 7,810

Intangible Assets, Goodwill a40

Intangible Assets, Goodwill and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	The following table reflects the components of intangible assets being amortized at December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 Weighted Amortization Period in Years Gross Carrying Amount Accumulated Amortization Carrying Value Gross Carrying Amount Accumulated Amortization Carrying Value Sodium Minerals and Sulfur Services: Customer relationships 5 $ 94,654 $ 92,493 $ 2,161 $ 94,654 $ 89,756 $ 4,898 Licensing agreements 6 38,678 36,528 2,150 38,678 34,204 4,474 Non-compete agreement 3 800 89 711 — — — Segment total 134,132 129,110 5,022 133,332 123,960 9,372 Onshore Facilities & Transportation: Customer relationships 5 35,430 35,082 348 35,430 33,676 1,754 Intangibles associated with lease 15 13,260 4,933 8,327 13,260 4,459 8,801 Segment total 48,690 40,015 8,675 48,690 38,135 10,555 Marine contract intangible 5 27,000 11,700 15,300 27,000 6,300 20,700 Offshore pipeline contract intangibles 19 158,101 20,109 137,992 158,101 11,788 146,313 Other 5 28,900 13,483 15,417 28,569 10,622 17,947 Total $ 396,823 $ 214,417 $ 182,406 $ 395,692 $ 190,805 $ 204,887
Schedule of Estimated Amortization Expense	The following table reflects our estimated amortization expense for each of the five subsequent fiscal years: 2018 2019 2020 2021 2022 Sodium Minerals and Sulfur Services: Customer relationships $ 2,161 $ — $ — $ — $ — Licensing agreements 2,150 — — — — Non Compete 267 267 177 — — Onshore Facilities & Transportation: Customer relationships 41 39 38 37 35 Intangibles associated with lease 474 474 474 474 474 Marine contract intangibles 5,400 5,400 4,500 — — Offshore pipeline contract intangibles 8,321 8,321 8,321 8,321 8,321 Other 2,974 2,952 2,921 1,810 1,652 Total $ 21,788 $ 17,453 $ 16,431 $ 10,642 $ 10,482
Schedule of Other Assets	Other assets consisted of the following: December 31, 2017 2016 CO 2 volumetric production payments, net of amortization $ 2,175 $ 3,503 Deferred marine charges, net (1) 30,246 27,710 Other deferred costs and deposits 24,207 25,398 Other assets, net of amortization $ 56,628 $ 56,611 (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, 2017
Debt Disclosure [Abstract]
Schedule of Obligations Under Debt Arrangements	At December 31, 2017 and 2016 , our obligations under debt arrangements consisted of the following: December 31, 2017 December 31, 2016 Principal Unamortized Discount and Debt Issuance Costs Net Value Principal Unamortized Discount and Debt Issuance Costs Net Value Senior secured credit facility $ 1,099,200 $ — $ 1,099,200 $ 1,278,200 $ — 1,278,200 5.750% senior unsecured notes 145,170 1,303 143,867 350,000 4,163 345,837 6.750% senior unsecured notes 750,000 16,077 733,923 750,000 19,296 730,704 6.000% senior unsecured notes 400,000 5,691 394,309 400,000 6,758 393,242 5.625% senior unsecured notes 350,000 5,717 344,283 350,000 6,614 343,386 6.500% senior unsecured notes 550,000 9,462 540,538 — — — 6.250% senior unsecured notes 450,000 $ 8,002 441,998 — — — Total long-term debt $ 3,744,370 $ 46,252 $ 3,698,118 $ 3,128,200 $ 36,831 $ 3,091,369
Schedule of Summary of Applicable Redemption Periods	A summary of the applicable redemption periods is provided in the table below. 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2025 Notes 2026 Notes Redemption right beginning on February 15, 2017 August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to February 15, 2017 August 1, 2018 May 15, 2018 June 15, 2019 October 1, 2020 February 15, 2021

Partners' Capital, Mezzanine 42

Partners' Capital, Mezzanine and Equity Distributions (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of Paid Distributions	We paid distributions in 2018 , 2017 and 2016 as follows: Distribution For Date Paid Per Unit Amount Total Amount 2015 4th Quarter February 12, 2016 $ 0.6550 $ 72,036 2016 1st Quarter May 13, 2016 $ 0.6725 $ 73,961 2nd Quarter August 12, 2016 $ 0.6900 $ 81,406 3rd Quarter November 14, 2016 $ 0.7000 $ 82,585 4th Quarter February 14, 2017 $ 0.7100 $ 83,765 2017 1st Quarter May 15, 2017 $ 0.7200 $ 88,257 2nd Quarter August 14, 2017 $ 0.7225 $ 88,563 3rd Quarter November 14, 2017 $ 0.5000 $ 61,290 4th Quarter February 14, 2018 $ 0.5100 $ 62,515
New Common Units Issued to the Public For Cash	The new common units issued in 2017 , 2016 and 2015 to the public for cash were as follows: Period Purchaser of Common Units Units Gross Unit Price Issuance Value Costs Net Proceeds March 2017 Public 4,600 $ 30.65 $ 140,990 $ (477 ) $ 140,513 July 2016 Public 8,000 $ 37.90 $ 303,200 $ (4,748 ) $ 298,452 July 2015 Public 10,350 $ 43.77 $ 453,020 $ (15,856 ) $ 437,164 April 2015 Public 4,600 $ 44.42 $ 204,332 $ (6,164 ) $ 198,168
Schedule of Initial Measurement of Class A Convertible Preferred Units	The preferred units were initially recognized at their issuance date fair value, net of issuance costs. As discussed above, a portion of the net proceeds were allocated to the Preferred Distribution Rate Reset Election and recorded in Other long term liabilities on the Consolidated Balance Sheet as described below: Year Ended December 31, 2017 Transaction price, gross 750,000 Transaction cost to other third parties (23,581 ) Transaction price, net 726,419 Allocation of Net Transaction Price Preferred Units, net 691,969 Preferred Distribution Rate Reset Election ( Note 18 ) 34,450 726,419
Schedule of Changes in Class A Convertible Preferred Units	The following table shows the change in our Class A Convertible Preferred Units from initial measurement at September 1, 2017 to December 31, 2017: Year Ended December 31, 2017 Balance as of December 31, 2016 — Issuance of Preferred Units, net 726,419 Allocation to Preferred Distribution Rate Reset Election ( Note 18 ) (34,450 ) Distribution paid-in-kind 5,469 Allocation of Distribution paid-kind to Preferred Distribution Rate Reset Election ( Note 18 ) (287 ) Balance as of December 31, 2017 697,151 Year Ended December 31, 2017 Balance as of December 31, 2016 — Issuance of Preferred Units 22,249,494 Distribution paid-in-kind 162,234 Balance as of December 31, 2017 22,411,728

Net Income Per Common Unit (Tab

Net Income Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Net Income per Common Unit [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit (in thousands, except per unit amounts): Year Ended 2017 2016 2015 Net Income Attributable to Genesis Energy L.P. $ 82,647 $ 113,249 $ 422,528 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (21,995 ) — — Net Income Available to Common Unitholders $ 60,652 $ 113,249 $ 422,528 Weighted Average Outstanding Units 121,546 113,433 103,004 Basic and Diluted Net Income per Common Unit $ 0.50 $ 1.00 $ 4.10

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information for each year presented below is as follows: Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total Year Ended December 31, 2017 Segment Margin (a) $ 317,540 $ 130,333 $ 96,376 $ 50,294 $ 594,543 Capital expenditures (b) $ 8,815 $ 1,354,469 $ 149,123 $ 68,414 $ 1,580,821 Revenues: External customers $ 319,455 $ 470,789 $ 1,044,083 $ 194,050 $ 2,028,377 Intersegment (c) (1,216 ) (8,167 ) (1,854 ) 11,237 $ — Total revenues of reportable segments $ 318,239 $ 462,622 $ 1,042,229 $ 205,287 $ 2,028,377 Year Ended December 31, 2016 Segment Margin (a) $ 336,620 $ 79,508 $ 83,364 $ 70,079 $ 569,571 Capital expenditures (b) $ 46,277 $ 2,274 $ 316,638 $ 78,804 $ 443,993 Revenues: External customers $ 332,514 $ 180,665 $ 993,103 $ 206,211 $ 1,712,493 Intersegment (c) 2,165 (9,162 ) 187 6,810 $ — Total revenues of reportable segments $ 334,679 $ 171,503 $ 993,290 $ 213,021 $ 1,712,493 Year Ended December 31, 2015 Segment Margin (a) $ 197,723 $ 80,246 $ 95,394 $ 103,222 $ 476,585 Capital expenditures (b) $ 1,527,320 $ 1,595 $ 409,687 $ 69,009 $ 2,007,611 Revenues: External customers $ 140,230 $ 187,257 $ 1,688,850 $ 230,192 $ 2,246,529 Intersegment (c) — (9,377 ) 812 8,565 $ — Total revenues of reportable segments $ 140,230 $ 177,880 $ 1,689,662 $ 238,757 $ 2,246,529 Total assets by reportable segment were as follows: December 31, 2017 December 31, 2016 December 31, 2015 Offshore pipeline transportation 2,486,803 2,575,335 2,623,478 Sodium minerals and sulfur services 1,848,188 395,043 394,626 Onshore facilities and transportation 1,927,976 1,875,403 1,615,335 Marine transportation 824,777 813,722 777,952 Other assets 49,737 43,089 48,208 Total consolidated assets $ 7,137,481 $ 5,702,592 $ 5,459,599 (a) A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for each year is presented below. (b) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. During the year ended December 31, 2016, capital expenditures in our offshore pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in Deepwater Gateway. Additionally, in 2015, there was $1.5 billion in capital spending to fund our Enterprise acquisition. Capital spending in this segment also included $2.5 million during the year ended December 31, 2015 representing capital contributions to our SEKCO pipeline to fund our share of the construction costs for its pipeline (as prior to our Enterprise acquisition in July 2015, we owned a 50% interest in the SEKCO pipeline with Enterprise owning the remaining 50% ). (c) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
Reconciliation of Segment Margin To (Loss) Income Before Income Taxes	Reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P.: Year Ended 2017 2016 2015 Total Segment Margin $ 594,543 $ 569,571 $ 476,585 Corporate general and administrative expenses (60,029 ) (40,905 ) (61,370 ) Depreciation, depletion, amortization and accretion (262,021 ) (230,563 ) (155,081 ) Interest expense (176,762 ) (139,947 ) (100,596 ) Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1) (31,852 ) (39,276 ) (43,018 ) Non-cash items not included in Segment Margin (14,305 ) (3,221 ) 2,809 Cash payments from direct financing leases in excess of earnings (6,921 ) (6,277 ) (5,685 ) Gain on step up of historical basis — — 332,380 Loss on extinguishment of debt (6,242 ) — (19,225 ) Differences in timing of cash receipts for certain contractual arrangements (2) 17,540 13,253 6,359 Gain on sales of assets 40,311 — — Other, net (2,985 ) (6,044 ) (6,643 ) Non-cash provision for leased items no longer in use (12,589 ) — — Income tax expense 3,959 (3,342 ) (3,987 ) Net income attributable to Genesis Energy, L.P. $ 82,647 $ 113,249 $ 422,528 (1) Includes distributions attributable to the period and received during or promptly following such period. (2) Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

Transactions with Related Par45

Transactions with Related Parties (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Transactions With Related Parties	ransactions with related parties were as follows: Year Ended December 31, 2017 2016 2015 Revenues: Sales of CO 2 to Sandhill Group, LLC (1) $ 2,820 $ 3,097 $ 3,259 Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2) 12,357 10,844 4,536 Revenues from product sales to ANSAC 124,536 — — Expenses: Amounts paid to our CEO in connection with the use of his aircraft $ 660 $ 660 $ 690 Charges for products purchased from Poseidon Oil Pipeline Company, LLC (2) 986 1,007 464 Charges for services from ANSAC 2,242 — — (1) We own a 50% interest in Sandhill Group, LLC. (2) We own a 64% interest in Poseidon Oil Pipeline Company, LLC. As of December 31, 2017 , our receivables from and payables to ANSAC were: December 31 2017 Receivables: ANSAC $ 74,490 Payables: ANSAC $ 1,223 ANSAC is considered a variable interest entity (VIE) as we do experience certain risks and rewards from our relationship with them. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC.

Supplemental Cash Flow Inform46

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
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, 2017 2016 2015 (Increase) decrease in: Accounts receivable $ (140,948 ) $ (9,859 ) $ 99,384 Inventories 49,055 (54,361 ) 3,811 Deferred charges (3,622 ) (3,902 ) (11,916 ) Other current assets (410 ) 3,059 6,417 Increase (decrease) in: Accounts payable 97,569 (17,426 ) (101,581 ) Accrued liabilities 8,512 (8,161 ) 9,257 Net changes in components of operating assets and liabilities $ 10,156 $ (90,650 ) $ 5,372

Equity-Based Compensation Pla47

Equity-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Summary of Service-Based And Performance-Based Awards	A summary of our phantom unit activity for our service-based and performance-based awards is set forth below: Service-Based Awards Performance-Based Awards Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Number of Phantom Units Average Grant Date Fair Value Total Value (in thousands) Unvested at December 31, 2016 181,230 $ 40.59 $ 7,356 483,232 $ 38.82 $ 18,757 Granted 102,868 $ 32.27 3,320 194,346 $ 32.43 6,303 Forfeited (3,402 ) $ 37.22 (127 ) (17,410 ) $ 35.43 (617 ) Settled (40,859 ) $ 53.84 (2,200 ) (77,793 ) $ 54.18 (4,215 ) Unvested at December 31, 2017 239,837 $ 34.81 $ 8,349 582,375 $ 34.73 $ 20,228
Expense Related To Equity-Based Compensation Plans	Equity-based compensation expense during the three years ended December 31, 2017 was as follows: Expense Related to Equity-Based Compensation Plans Consolidated Statement of Operations 2017 2016 2015 Onshore facilities and transportation operating costs $ (1,137 ) $ 1,688 $ 1,185 Marine transportation operating costs (483 ) 1,089 851 Sodium minerals and sulfur services operating costs (533 ) 547 227 Offshore pipeline operating costs (152 ) 681 94 General and administrative expenses (2,272 ) 4,575 4,565 Total $ (4,577 ) $ 8,580 $ 6,922

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivatives Entered Into Hedge Inventory or Fixed Price Purchase Commitments	At December 31, 2017 , we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. Sell (Short) Contracts Buy (Long) Contracts Designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 297 — Weighted average contract price per bbl $ 57.70 — Not qualifying or not designated as hedges under accounting rules: Crude oil futures: Contract volumes (1,000 bbls) 223 152 Weighted average contract price per bbl $ 56.86 $ 57.30 Fuel oil futures: Contract volumes (1,000 bbls) 260 20 Weighted average contract price per bbl $ 55.01 $ 53.20 Crude oil options: Contract volumes (1,000 bbls) 80 45 Weighted average premium received $ 0.85 $ 0.24
Schedule of Accounting Treatment And Classification of Derivative Instruments	The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements. Derivative Instrument Hedged Risk Impact of Unrealized Gains and Losses Consolidated Balance Sheets Consolidated Statements of Operations Designated as hedges under accounting guidance: Crude oil futures contracts (fair value hedge) Volatility in crude oil prices - effect on market value of inventory Derivative is recorded in Other current assets (offset against margin deposits) and offsetting change in fair value of inventory is recorded in Inventories Excess, if any, over effective portion of hedge is recorded in Onshore facilities and transportation costs - product costs Effective portion is offset in cost of sales against change in value of inventory being hedged Not qualifying or not designated as hedges under accounting guidance: Commodity hedges consisting of crude oil, heating oil and natural gas futures and forward contracts and call options Volatility in crude oil and petroleum products prices - effect on market value of inventory or purchase commitments Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities Entire amount of change in fair value of derivative is recorded in Onshore facilities and transportation costs - product costs Preferred Distribution Rate Reset Election This instrument is not related to a risk, but is rather part of a host contract with the issuance of our Preferred Units Derivative is recorded in Other long-term liabilities Entire amount of change in fair value of derivative is recorded in Other income (expense)
Schedule of Fair Value of Derivative Assets And Liabilities	Fair Value Consolidated Balance Sheets Location December 31, 2017 December 31, 2016 Asset Derivatives: Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized assets Current Assets - Other $ 505 $ 443 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (505 ) (443 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Total asset derivatives $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized assets Current Assets - Other $ 54 $ 3,321 Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (54 ) (3,321 ) Net amount of assets presented in the Consolidated Balance Sheets $ — $ — Liability Derivatives: Preferred Distribution Rate Reset Election (2) Other Long-Term Liabilities (2) $ (45,209 ) — Commodity derivatives—futures and call options (undesignated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (1,203 ) $ (1,772 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 1,203 1,772 Net amount of liabilities presented in the Consolidated Balance Sheets $ — $ — Commodity derivatives—futures and call options (designated hedges): Gross amount of recognized liabilities Current Assets - Other (1) $ (863 ) $ (9,506 ) Gross amount offset in the Consolidated Balance Sheets Current Assets - Other (1) 338 7,589 Net amount of liabilities presented in the Consolidated Balance Sheets $ (525 ) $ (1,917 ) (1) These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other. (2) Refer to Note 11 and Note 19 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.
Schedule of Effect on Consolidated Statements of Operations And Other Comprehensive Income (Loss)	Effect on Operating Results Amount of Gain (Loss) Recognized in Income Year Ended Consolidated Statements of Operations Location 2017 2016 2015 Commodity derivatives—futures and call options: Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ 5,116 $ (13,195 ) $ (1,101 ) Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs (1,314 ) (5,847 ) 16,026 Total commodity derivatives $ 3,802 $ (19,042 ) $ 14,925 Preferred Distribution Rate Reset Election ( Note 19 ) Other Expense $ (10,472 ) $ — $ —

Fair-Value Measurements (Tables

Fair-Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
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, 2017 and 2016 . December 31, 2017 December 31, 2016 Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Commodity derivatives: Assets $ 559 $ — $ — $ 3,764 $ — $ — Liabilities $ (2,066 ) $ — $ — $ (11,278 ) $ — $ — Preferred Distribution Rate Reset Election $ — $ — $ (45,209 ) $ — $ — $ —
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3: Year Ended December 31, 2017 Beginning Balance — Initial valuation of Preferred Distribution Rate Reset Election $ (34,450 ) Net Loss for the period included in earnings (10,472 ) Allocation of Distribution Paid-in-kind (287 ) Ending Balance $ (45,209 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Changes in Benefit Obligations, Plan Assets and Funded Status with Amounts Recognized in Consolidated Balance Sheet	The change in benefit obligations, plan assets and funded status along with amounts recognized in the Consolidated Balance Sheet are as follows: December 31, 2017 Change in benefit obligation: Benefit Obligation, beginning of year $ — Service Cost 1,749 Interest Cost 267 Actuarial Loss 992 Benefits Paid (56 ) Acquisition of Alkali Business 19,578 Benefit Obligation, end of year 22,530 Change in plan assets: Fair Value of Plan Assets, beginning of year — Actual Return on Plan Assets 647 Employer Contributions 2,250 Benefits Paid (56 ) Acquisition of Alkali Business 10,465 Fair Value of Plan assets, end of year 13,306 Funded Status at end of period $ (9,224 ) Amounts recognized in the Statement of Financial Position Non-current assets $ — Current liabilities — Non-current Liabilities (9,224 ) Net Asset (Liability) at end of year $ (9,224 ) Amounts recognized in accumulated other comprehensive loss: Net actuarial loss 604 Amounts recognized in accumulated other comprehensive loss: $ 604
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 2018 Contributions by Employer $ 3,898 Future Expected Benefit Payments 2018 $ 413 2019 676 2020 869 2021 983 2022 1,099 2023-2027 7,672
Components of Net Periodic Costs	The components of net periodic pension costs for the Alkali benefit plan are as follows: December 31, 2017 Service Cost $ 1,749 Interest Cost 267 Expected Return on Assets (259 ) $ 1,757
Weighted Average Assumptions Used To Determine Benefit Obligation	The Alkali Business benefit plan is administered by a Board-appointed committee that has fiduciary responsibility for the plan's management. The committee is responsible for the oversight and management of the plan's investments. The committee maintains an investment policy that provides guidelines for selection and retention of investment managers or funds, allocation of plan assets and performance review procedures and updating of the policy. The objective of the committee's investment policy is to manage the plan assets in such a way that will allow for the on-going payment of the Company's obligation to the beneficiaries. Weighted average assumptions used to determine benefit obligation: December 31, 2017 Discount Rate 3.90 % Expected Long-term Rate of Return 6.28 % Rate of Compensation Increase N/A The discount rate used to determine the net periodic cost at the beginning of the period was 4.15% .
Pension Plan Asset Allocations	Our Pension Plan asset allocations at December 31, 2017 by asset category are as follows: December 31, 2017 Target % Actual % Equity securities 41-60% 41 % Fixed income securities 40-50% 50 % Other 0-10% 9 % A summary of total investments for our pension plan assets measured at fair value at December 31, 2017 is presented below: December 31, 2017 Level 1 Level 2 Level 3 Total Cash and cash equivalents 260 — — 260 Equity securities 2,518 — — 2,518 Mutual and other exchange traded funds 10,528 — — 10,528 13,306 — — 13,306

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Future Minimum Rental Payments Under All Non-Cancelable Operating Leases	The future minimum rental payments under all non-cancelable operating leases as of December 31, 2017 , were as follows (in thousands): Office Space Transportation Equipment Terminals and Tanks Total 2018 $ 3,972 $ 25,871 $ 14,737 $ 44,580 2019 3,951 25,209 12,593 41,753 2020 3,984 23,403 8,833 36,220 2021 3,233 17,818 6,545 27,596 2022 2,693 16,317 4,754 23,764 2023 and thereafter 4,696 55,614 55,627 115,937 Total minimum lease obligations $ 22,529 $ 164,232 $ 103,089 $ 289,850
Total Operating Lease Expense	Total operating lease expense from our continuing operations was as follows (in thousands): Year Ended December 31, 2017 $ 36,933 Year Ended December 31, 2016 $ 41,906 Year Ended December 31, 2015 $ 36,833

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Expense (Benefit)	Our income tax (benefit) expense is as follows: Year Ended December 31, 2017 2016 2015 Current: Federal $ — $ — $ — State 100 1,200 1,200 Total current income tax expense (benefit) $ 100 $ 1,200 $ 1,200 Deferred: Federal $ (5,530 ) $ 1,862 $ 2,478 State 1,471 280 309 Total deferred income tax expense (benefit) $ (4,059 ) $ 2,142 $ 2,787 Total income tax expense (benefit) $ (3,959 ) $ 3,342 $ 3,987
Deferred Tax Assets And Liabilities	Deferred tax assets and liabilities consist of the following: December 31, 2017 2016 Deferred tax assets: Net operating loss carryforwards $ 9,506 $ 10,787 Total long-term deferred tax asset 9,506 10,787 Valuation allowances (1,285 ) (869 ) Total deferred tax assets $ 8,221 $ 9,918 Deferred tax liabilities: Long-term: Fixed assets $ (3,896 ) $ (4,480 ) Intangible assets (15,797 ) (20,693 ) Other (441 ) (716 ) Total long-term liability (20,134 ) (25,889 ) Total deferred tax liabilities $ (20,134 ) $ (25,889 ) Total net deferred tax liability $ (11,913 ) $ (15,971 )
Federal Statutory Income Tax Rate To Income Before Income Taxes	: Year Ended December 31, 2017 2016 2015 Income from operations before income taxes $ 78,120 $ 114,424 $ 425,572 Partnership income not subject to federal income tax (77,704 ) (109,111 ) (418,500 ) Income subject to federal income taxes $ 416 $ 5,313 $ 7,072 Tax expense at federal statutory rate $ 146 $ 1,860 $ 2,475 State income taxes, net of federal tax 1,396 949 928 Return to provision, federal and state (163 ) (198 ) (193 ) Other (68 ) 731 777 Remeasurement of deferred taxes due to enacted tax rate change (5,270 ) — — Income tax expense (benefit) $ (3,959 ) $ 3,342 $ 3,987 Effective tax rate on income from operations before income taxes (5 )% 3 % 1 %

Quarterly Financial Data (Una53

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Summary of Unaudited Quarterly Financial Data	The table below summarizes our unaudited quarterly financial data for 2017 and 2016 . 2017 Quarters First Second Third Fourth Revenues from continuing operations $ 415,491 $ 406,723 $ 486,114 $ 720,049 Operating income $ 52,597 $ 61,447 $ 43,100 $ 63,407 Net income $ 26,938 $ 33,580 $ 6,160 $ 15,401 Net loss attributable to noncontrolling interest $ 152 $ 153 $ 152 $ 111 Net income attributable to Genesis Energy, L.P. $ 27,090 $ 33,733 $ 6,312 $ 15,512 Basic and diluted net income per common unit: Net income per common unit $ 0.23 $ 0.28 $ 0.01 $ (0.01 ) Cash distributions per common unit (1) $ 0.7100 $ 0.7200 $ 0.7225 $ 0.5000 2016 Quarters First Second Third Fourth Revenues from continuing operations $ 378,414 $ 445,976 $ 460,050 $ 428,053 Operating income $ 59,848 $ 47,988 $ 55,179 $ 43,412 Net income $ 35,177 $ 23,601 $ 31,983 $ 20,321 Net loss (income) attributable to noncontrolling interest $ 126 $ 126 $ 118 $ 1,797 Net income attributable to Genesis Energy, L.P. $ 35,303 $ 23,727 $ 32,101 $ 22,118 Basic and diluted net income per common unit: Net income per common unit $ 0.32 $ 0.22 $ 0.28 $ 0.19 Cash distributions per common unit (1) $ 0.6550 $ 0.6725 $ 0.6900 $ 0.7000 (1) Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Finan54

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Statements	The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors: Condensed Consolidating Balance Sheet December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 8,340 $ 695 $ — $ 9,041 Other current assets 50 — 614,682 12,316 (56 ) 626,992 Total current assets 56 — 623,022 13,011 (56 ) 636,033 Fixed Assets, at cost — — 5,523,431 77,584 — 5,601,015 Less: Accumulated depreciation — — (708,269 ) (26,717 ) — (734,986 ) Net fixed assets — — 4,815,162 50,867 — 4,866,029 Mineral Leaseholds — — 564,506 — — 564,506 Goodwill — — 325,046 — — 325,046 Other assets, net 14,083 — 378,371 126,300 (154,437 ) 364,317 Advances to affiliates 3,808,712 — — 85,423 (3,894,135 ) — Equity investees and other investments — — 381,550 — — 381,550 Investments in subsidiaries 2,689,861 — 82,616 — (2,772,477 ) — Total assets $ 6,512,712 $ — $ 7,170,273 $ 275,601 $ (6,821,105 ) $ 7,137,481 LIABILITIES AND CAPITAL Current liabilities $ 46,086 $ — $ 399,017 $ 11,417 $ (256 ) $ 456,264 Senior secured credit facilities 1,099,200 — — — — 1,099,200 Senior unsecured notes 2,598,918 — — — — 2,598,918 Deferred tax liabilities — — 11,913 — — 11,913 Advances from affiliates — — 3,894,027 — (3,894,027 ) — Other liabilities 45,210 — 182,414 183,237 (154,290 ) 256,571 Total liabilities 3,789,414 — 4,487,371 194,654 (4,048,573 ) 4,422,866 Mezzanine Capital: Class A Convertible Preferred Units 697,151 — — — — 697,151 Partners’ capital, common units 2,026,147 — 2,683,506 89,026 (2,772,532 ) 2,026,147 Accumulated other comprehensive income (loss) (1) — — (604 ) — — (604 ) Noncontrolling interests — — — (8,079 ) — (8,079 ) Total liabilities, mezzanine capital and partners’ capital $ 6,512,712 $ — $ 7,170,273 $ 275,601 $ (6,821,105 ) $ 7,137,481 (1) The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our Guarantor Subsidiaries. Condensed Consolidating Balance Sheet December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated ASSETS Current assets: Cash and cash equivalents $ 6 $ — $ 6,360 $ 663 $ — $ 7,029 Other current assets 50 — 340,555 12,237 (302 ) 352,540 Total current assets 56 — 346,915 12,900 (302 ) 359,569 Fixed Assets, at cost — — 4,685,811 77,585 — 4,763,396 Less: Accumulated depreciation — — (524,315 ) (24,217 ) — (548,532 ) Net fixed assets — — 4,161,496 53,368 — 4,214,864 Mineral Leaseholds — — — — — — Goodwill — — 325,046 — — 325,046 Other assets, net 10,696 — 390,214 133,980 (140,533 ) 394,357 Advances to affiliates 2,650,930 — — 73,295 (2,724,225 ) — Equity investees and other investments — — 408,756 — — 408,756 Investments in subsidiaries 2,594,882 — 80,735 — (2,675,617 ) — Total assets $ 5,256,564 $ — $ 5,713,162 $ 273,543 $ (5,540,677 ) $ 5,702,592 LIABILITIES AND CAPITAL Current liabilities $ 34,864 $ — $ 211,591 $ 14,505 $ (157 ) $ 260,803 Senior secured credit facilities 1,278,200 — — — — 1,278,200 Senior unsecured notes 1,813,169 — — — — 1,813,169 Deferred tax liabilities — — 25,889 — — 25,889 Advances from affiliates — — 2,724,224 — (2,724,224 ) — Other liabilities — — 165,266 179,592 (140,377 ) 204,481 Total liabilities 3,126,233 — 3,126,970 194,097 (2,864,758 ) 3,582,542 Mezzanine Capital Class A Convertible Preferred Units — — — — — — Partners' capital 2,130,331 — 2,586,192 89,727 (2,675,919 ) 2,130,331 Accumulated other comprehensive income (loss) — — — — — — Noncontrolling interests — — — (10,281 ) — (10,281 ) Total liabilities, mezzanine capital and partners’ capital $ 5,256,564 $ — $ 5,713,162 $ 273,543 $ (5,540,677 ) $ 5,702,592 Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 318,239 $ — $ — $ 318,239 Sodium minerals and sulfur services — — 460,790 9,252 (7,420 ) 462,622 Marine transportation — — 205,287 — — 205,287 Onshore facilities and transportation — — 1,023,293 18,936 — 1,042,229 Total revenues — — 2,007,609 28,188 (7,420 ) 2,028,377 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 967,558 1,089 — 968,647 Marine transportation costs — — 154,606 — — 154,606 Sodium minerals and sulfur services operating costs — — 332,209 9,129 (7,420 ) 333,918 Offshore pipeline transportation operating costs — — 69,225 2,840 — 72,065 General and administrative — — 66,421 — — 66,421 Depreciation and amortization — — 249,980 2,500 — 252,480 Gain on sale of assets — — (40,311 ) — — (40,311 ) Total costs and expenses — — 1,799,688 15,558 (7,420 ) 1,807,826 OPERATING INCOME — — 207,921 12,630 — 220,551 Equity in earnings of equity investees — — 51,046 — — 51,046 Equity in earnings of subsidiaries 276,341 — (520 ) — (275,821 ) — Interest (expense) income, net (176,979 ) — 14,122 (13,905 ) — (176,762 ) Other expense (16,715 ) — — — — (16,715 ) Income before income taxes 82,647 — 272,569 (1,275 ) (275,821 ) 78,120 Income tax benefit (expense) — — 3,928 31 — 3,959 NET INCOME 82,647 — 276,497 (1,244 ) (275,821 ) 82,079 Net loss attributable to noncontrolling interests — — — 568 — 568 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 82,647 $ — $ 276,497 $ (676 ) $ (275,821 ) $ 82,647 Less: Accumulated distributions attributable to Class A Convertible Preferred Units (21,995 ) — — — — (21,995 ) NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 60,652 $ — $ 276,497 $ (676 ) $ (275,821 ) $ 60,652 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 334,679 $ — $ 334,679 Sodium minerals and sulfur services — — 171,389 7,873 (7,759 ) 171,503 Marine transportation — — 213,021 — — 213,021 Onshore facilities and transportation — — 972,794 20,496 — 993,290 Total revenues — — 1,691,883 28,369 (7,759 ) 1,712,493 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 923,567 1,060 — 924,627 Marine transportation costs — — 142,551 — — 142,551 Sodium minerals and sulfur services operating costs — — 90,711 8,491 (7,759 ) 91,443 Offshore pipeline transportation operating costs — — 68,791 10,833 — 79,624 General and administrative — — 45,625 — — 45,625 Depreciation and amortization — — 219,696 2,500 — 222,196 Total costs and expenses — — 1,490,941 22,884 (7,759 ) 1,506,066 OPERATING INCOME — — 200,942 5,485 — 206,427 Equity in earnings of equity investees — — 47,944 — — 47,944 Equity in earnings of subsidiaries 253,048 — (6,744 ) — (246,304 ) — Interest (expense) income, net (139,799 ) — 14,407 (14,555 ) — (139,947 ) Other expense, net — — — — — — Income before income taxes 113,249 — 256,549 (9,070 ) (246,304 ) 114,424 Income tax expense — — (3,337 ) (5 ) — (3,342 ) NET INCOME 113,249 — 253,212 (9,075 ) (246,304 ) 111,082 Net loss attributable to noncontrolling interests — — — 2,167 — 2,167 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Less: Accumulated distributions attributable to Class A Convertible Preferred Units — — — — — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 113,249 $ — $ 253,212 $ (6,908 ) $ (246,304 ) $ 113,249 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated REVENUES: Offshore pipeline transportation services $ — $ — $ 137,681 $ 2,549 $ — $ 140,230 Sodium minerals and sulfur services — — 175,132 11,942 (9,194 ) 177,880 Marine transportation — — 238,757 — — 238,757 Onshore facilities and transportation — — 1,665,917 23,745 — 1,689,662 Total revenues — — 2,217,487 38,236 (9,194 ) 2,246,529 COSTS AND EXPENSES: Onshore facilities and transportation costs — — 1,601,972 836 — 1,602,808 Marine transportation costs — — 135,200 — — 135,200 Sodium minerals and sulfur services operating costs — — 94,241 11,759 (9,194 ) 96,806 Offshore pipeline transportation operating costs — — 38,459 1,254 — 39,713 General and administrative — — 64,995 — — 64,995 Depreciation and amortization — — 141,785 8,355 — 150,140 Total costs and expenses — — 2,076,652 22,204 (9,194 ) 2,089,662 OPERATING INCOME — — 140,835 16,032 — 156,867 Equity in earnings of equity investees — — 54,450 — — 54,450 Equity in earnings of subsidiaries 542,226 — 2,053 — (544,279 ) — Gain on basis step up on historical interest — — 332,380 — — 332,380 Interest (expense) income, net (100,494 ) — 15,042 (15,144 ) — (100,596 ) Other income/(expense), net (19,204 ) — 1,675 — — (17,529 ) Income before income taxes 422,528 — 546,435 888 (544,279 ) 425,572 Income tax expense — — (4,036 ) 49 — (3,987 ) NET INCOME $ 422,528 $ — $ 542,399 $ 937 $ (544,279 ) $ 421,585 Net loss attributable to noncontrolling interest $ — $ — $ — $ 943 $ — 943 NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 422,528 $ — $ 542,399 $ 1,880 $ (544,279 ) $ 422,528 Less: Accumulated distributions attributable to Class A Convertible Preferred Units $ — $ — $ — $ — $ — — NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 422,528 $ — $ 542,399 $ 1,880 $ (544,279 ) $ 422,528 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 162,980 $ — $ 481,727 $ (4,585 ) $ (301,264 ) $ 338,858 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (250,593 ) — — (250,593 ) Cash distributions received from equity investees - return of investment — — 20,280 — — 20,280 Investments in equity investees (140,513 ) — (4,647 ) — 140,513 (4,647 ) Acquisitions — — (1,325,759 ) — — (1,325,759 ) Intercompany transfers (1,157,781 ) — — — 1,157,781 — Repayments on loan to non-guarantor subsidiary — — 6,764 — (6,764 ) — Contributions in aid of construction costs — — 124 — — 124 Proceeds from asset sales — — 85,722 — — 85,722 Other, net — — — — — — Net cash (used in) provided by investing activities (1,298,294 ) — (1,468,109 ) — 1,291,530 (1,474,873 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,458,700 — — — — 1,458,700 Repayments on senior secured credit facility (1,637,700 ) — — — — (1,637,700 ) Proceeds from issuance of senior unsecured notes, including premium 1,000,000 — — — — 1,000,000 Proceeds from issuance of Class A convertible preferred units, net 726,419 — — — — 726,419 Repayment of senior unsecured notes (204,830 ) — — — — (204,830 ) Debt issuance costs (25,913 ) — — — — (25,913 ) Intercompany transfers — — 1,169,781 (12,000 ) (1,157,781 ) — Issuance of common units for cash, net 140,513 — 140,513 — (140,513 ) 140,513 Distributions to partners/owners (321,875 ) — (321,875 ) — 321,875 (321,875 ) Contributions from noncontrolling interest — — — 2,770 — 2,770 Other, net — — (57 ) 13,847 (13,847 ) (57 ) Net cash provided by financing activities 1,135,314 — 988,362 4,617 (990,266 ) 1,138,027 Net decrease in cash and cash equivalents — — 1,980 32 — 2,012 Cash and cash equivalents at beginning of period 6 — 6,360 663 — 7,029 Cash and cash equivalents at end of period $ 6 $ — $ 8,340 $ 695 $ — $ 9,041 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ 179,853 $ — $ 398,320 $ 9,586 $ (289,421 ) $ 298,338 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (463,100 ) — — (463,100 ) Cash distributions received from equity investees - return of investment — — 21,353 — — 21,353 Investments in equity investees (298,020 ) — — — 298,020 — Acquisitions — — (25,394 ) — — (25,394 ) Intercompany transfers (31,436 ) — — — 31,436 — Repayments on loan to non-guarantor subsidiary — — 6,113 — (6,113 ) — Contributions in aid of construction costs — — 13,374 — — 13,374 Proceeds from assets sales — — 3,609 — — 3,609 Other, net — — (151 ) — — (151 ) Net cash (used in) provided by investing activities (329,456 ) — (444,196 ) — 323,343 (450,309 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,115,800 — — — — 1,115,800 Repayments on senior secured credit facility (952,600 ) — — — — (952,600 ) Debt issuance costs (1,578 ) — — — — (1,578 ) Intercompany transfers — — 57,701 (26,264 ) (31,437 ) — Issuance of common units for cash, net 298,020 — 298,020 — (298,020 ) 298,020 Distributions to partners/owners (310,039 ) — (310,039 ) — 310,039 (310,039 ) Contributions from noncontrolling interest — — — 236 — 236 Other, net — — (1,734 ) 14,504 (14,504 ) (1,734 ) Net cash provided by (used in) financing activities 149,603 — 43,948 (11,524 ) (33,922 ) 148,105 Net increase (decrease) in cash and cash equivalents — — (1,928 ) (1,938 ) — (3,866 ) Cash and cash equivalents at beginning of period 6 — 8,288 2,601 — 10,895 Cash and cash equivalents at end of period $ 6 $ — $ 6,360 $ 663 $ — $ 7,029 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 Genesis Energy, L.P. (Parent and Co-Issuer) Genesis Energy Finance Corporation (Co-Issuer) Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Genesis Energy, L.P. Consolidated Net cash (used in) provided by operating activities $ (14,082 ) $ — $ 308,144 $ 45,125 $ (49,651 ) $ 289,536 CASH FLOWS FROM INVESTING ACTIVITIES: Payments to acquire fixed and intangible assets — — (495,774 ) — — (495,774 ) Cash distributions received from equity investees - return of investment 186,026 — 25,645 — (186,026 ) 25,645 Investments in equity investees (633,761 ) — (3,045 ) — 633,761 (3,045 ) Acquisitions — — (1,520,299 ) — — (1,520,299 ) Intercompany transfers (1,240,973 ) — — — 1,240,973 — Repayments on loan to non-guarantor subsidiary — — 5,524 — (5,524 ) — Contributions in aid of construction costs — — 3,179 — — 3,179 Proceeds from asset sales — — 2,811 — — 2,811 Other, net — — (1,976 ) — — (1,976 ) Net cash (used in) provided by investing activities (1,688,708 ) — (1,983,935 ) — 1,683,184 (1,989,459 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured credit facility 1,525,050 — — — — 1,525,050 Repayments on senior secured credit facility (960,450 ) — — — — (960,450 ) Proceeds from issuance of senior unsecured notes 1,139,718 — — — — 1,139,718 Repayment of senior secured notes (350,000 ) — — — — (350,000 ) Debt issuance costs (28,901 ) — — — — (28,901 ) Distribution to partners/owners (256,389 ) — (256,389 ) — 256,389 (256,389 ) Distributions to noncontrolling interest — — (960 ) — — (960 ) Issuance of common units for cash, net 633,759 — 633,759 — (633,759 ) 633,759 Intercompany transfers — — 1,299,830 (58,857 ) (1,240,973 ) — Other, net — — (471 ) 15,190 (15,190 ) (471 ) Net cash provided by (used in) financing activities 1,702,787 — 1,675,769 (43,667 ) (1,633,533 ) 1,701,356 Net increase (decrease) in cash and cash equivalents (3 ) — (22 ) 1,458 — 1,433 Cash and cash equivalents at beginning of period 9 — 8,310 1,143 — 9,462 Cash and cash equivalents at end of period $ 6 $ — $ 8,288 $ 2,601 $ — $ 10,895

Organization (Details)

Organization (Details) $ in Thousands	Sep. 01, 2017USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Aug. 14, 2017USD ($)
Business Acquisition [Line Items]
Limited liabily company, ownership interest owned		100.00%
Payments to Acquire Businesses, Gross		$ 1,325,759	$ 25,394	$ 1,520,299
Number of divisions that constitute reportable segments | segment		4
Convertible Preferred Stock [Member]
Business Acquisition [Line Items]
Temporary Equity, Stock Issued During Period, Value, New Issues	$ 750,000
Convertible Preferred Stock [Member] | Private Placement [Member]
Business Acquisition [Line Items]
Temporary Equity, Stock Issued During Period, Value, New Issues	750,000
6.500% senior unsecured notes
Business Acquisition [Line Items]
Debt issued, aggregate principal amount		$ 550,000	$ 0
Alkali Business [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	1,325,000
Alkali Business [Member] | Convertible Preferred Stock [Member] | Private Placement [Member]
Business Acquisition [Line Items]
Temporary Equity, Stock Issued During Period, Value, New Issues	750,000
Alkali Business [Member] | 6.500% senior unsecured notes
Business Acquisition [Line Items]
Debt issued, aggregate principal amount	$ 550,000				$ 550,000

Summary of Significant Accoun56

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets	$ 0	$ 0	$ 0
Impairment of goodwill	$ 0	$ 0	$ 0
Minimum [Member] | Crude oil pipelines and natural gas pipelines and related assets
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	5 years
Minimum [Member] | Marine Vessels [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	20 years
Minimum [Member] | Onshore facilities, machinery, and equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	5 years
Minimum [Member] | Transportation equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Minimum [Member] | Building And Improvements [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	3 years
Maximum [Member] | Crude oil pipelines and natural gas pipelines and related assets
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	40 years
Maximum [Member] | Marine Vessels [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Maximum [Member] | Onshore facilities, machinery, and equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	30 years
Maximum [Member] | Transportation equipment
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	7 years
Maximum [Member] | Building And Improvements [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of property and equipment	10 years
Poseidon Oil Pipeline Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	64.00%
Neptune Pipeline Company LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	25.70%
Odyssey Pipeline L.L.C. [Member]
Summary Of Significant Accounting Policies [Line Items]
Equity investment, ownership percentage	29.00%

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details)

Sep. 01, 2017USD ($)

Mar. 24, 2017USD ($)

Jul. 27, 2016USD ($)

Jul. 24, 2015USD ($)platform

Jul. 23, 2015USD ($)

Jul. 22, 2015USD ($)

Apr. 10, 2015USD ($)

Jul. 31, 2015USD ($)shares

Dec. 31, 2017USD ($)shares

Dec. 31, 2016USD ($)shares

Dec. 31, 2015USD ($)

Aug. 14, 2017USD ($)

Jul. 25, 2015

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

$ 1,325,759,000

$ 25,394,000

$ 1,520,299,000

Proceeds from issuance of Class A convertible preferred units, net

$ 726,419,000

$ 0

0

Common units issued (in shares) | shares

122,579,218

117,979,218

Net proceeds received from sale of units, net of underwriter discounts

$ 140,513,000

$ 298,452,000

$ 437,164,000

$ 198,168,000

Asset retirement obligation, preliminary fair value

$ 20,940,000

Asset retirement obligation, retirement costs

$ 198,187,000

213,726,000

188,662,000

Poseidon Oil Pipeline Company [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

64.00%

SEKCO [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

50.00%

Accrued Liabilities [Member]

Business Acquisition [Line Items]

Asset retirement obligation, retirement costs

$ 20,900,000

22,400,000

Convertible Preferred Stock [Member]

Business Acquisition [Line Items]

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

$ 750,000,000

Convertible Preferred Stock [Member] | Private Placement [Member]

Business Acquisition [Line Items]

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

750,000,000

6.500% senior unsecured notes

Business Acquisition [Line Items]

Debt issued, aggregate principal amount

550,000,000

0

6.750% senior unsecured notes

Business Acquisition [Line Items]

Debt issued, aggregate principal amount

$ 750,000,000

750,000,000

750,000,000

Alkali Business [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

1,325,000,000

Payments to Acquire Businesses, Working Capital

$ 105,000,000

Acquisition related costs

$ 12,000,000

Alkali Business [Member] | Minimum [Member]

Business Acquisition [Line Items]

Estimated useful lives of property and equipment acquired

2 years

Alkali Business [Member] | Maximum [Member]

Business Acquisition [Line Items]

Estimated useful lives of property and equipment acquired

30 years

Alkali Business [Member] | Convertible Preferred Stock [Member] | Private Placement [Member]

Business Acquisition [Line Items]

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

$ 750,000,000

Proceeds from issuance of Class A convertible preferred units, net

726,400,000

Alkali Business [Member] | 6.500% senior unsecured notes

Business Acquisition [Line Items]

Debt issued, aggregate principal amount

$ 550,000,000

$ 550,000,000

Debt instrument, stated rate

6.50%

6.50%

Proceeds from issuance of debt, net of discount

$ 540,100,000

Enterprise Offshore Acquisition [Member]

Business Acquisition [Line Items]

Debt issued, aggregate principal amount

$ 750,000,000

Acquisition related costs

$ 1,000,000

15,000,000

Transaction costs related to business acquisition

$ 1,500,000,000

Business Acquisition, Effective Date of Acquisition

Jul. 24, 2015

Number of offshore hub platforms | platform

6

Common units issued (in shares) | shares

10,350,000

Net proceeds received from sale of units, net of underwriter discounts

$ 437,200,000

Estimated useful life of finite-lived intangible assets acquired

19 years

Asset retirement obligation, preliminary fair value

$ 158,200,000

Enterprise Offshore Acquisition [Member] | Poseidon Oil Pipeline Company [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

36.00%

Enterprise Offshore Acquisition [Member] | SEKCO [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

50.00%

50.00%

50.00%

Enterprise Offshore Acquisition [Member] | CHOPS [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

50.00%

50.00%

50.00%

Enterprise Offshore Acquisition [Member] | Independence Hub, LLC [Member]

Business Acquisition [Line Items]

Equity investment, ownership percentage

80.00%

Noncontrolling interest ownership percentage

20.00%

Enterprise Offshore Acquisition [Member] | Accrued Liabilities [Member]

Business Acquisition [Line Items]

Asset retirement obligation, retirement costs

$ 9,800,000

Enterprise Offshore Acquisition [Member] | Minimum [Member]

Business Acquisition [Line Items]

Estimated useful lives of property and equipment acquired

2 years

Enterprise Offshore Acquisition [Member] | Maximum [Member]

Business Acquisition [Line Items]

Estimated useful lives of property and equipment acquired

35 years

Enterprise Offshore Acquisition [Member] | 6.750% senior unsecured notes

Business Acquisition [Line Items]

Debt instrument, stated rate

6.75%

Proceeds from issuance of debt, net of discount

$ 728,600,000

Acquisitions (Schedule of Purch

Acquisitions (Schedule of Purchase Price Allocation) (Details) - USD ($) $ in Thousands	Sep. 01, 2017	Jul. 24, 2015
Alkali Business [Member]
Business Acquisition [Line Items]
Accounts receivable	$ 138,258
Inventories	34,929
Other current assets	13,254
Fixed assets	663,217
Mineral leaseholds	566,019
Intangible assets	800
Other assets	3,612
Accounts payable	(44,547)
Accrued liabilities	(36,884)
Other long-term liabilities	(13,658)
Total purchase price	$ 1,325,000
Enterprise Offshore Acquisition [Member]
Business Acquisition [Line Items]
Cash		$ 1,270
Accounts receivable		29,768
Inventories		600
Other current assets		10,432
Fixed assets		1,225,685
Intangible assets		79,050
Equity investees		352,535
Other assets		1,966
Accounts payable		(6,110)
Accrued liabilities		(18,662)
Other long-term liabilities		(161,412)
Noncontrolling interest		6,447
Total purchase price		$ 1,521,569

Acquisitions (Schedule of Selec

Acquisitions (Schedule of Selected Financial Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015
Alkali Business [Member]
Business Acquisition [Line Items]
Revenues	$ 277,011
Net income	$ 42,014
Enterprise Offshore Acquisition [Member]
Business Acquisition [Line Items]
Revenues		$ 101,444
Net income		$ 58,805

Acquisitions (Schedule of Pro F

Acquisitions (Schedule of Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per share)	$ 0.50	$ 1	$ 4.10
Alkali Business [Member]
Pro forma consolidated financial operating results:
Revenues	$ 2,549,438	$ 2,498,293	$ 3,043,529
Net Income Attributable to Genesis Energy, L.P.	84,010	120,515	416,118
Net Income Available to Common Unitholders	$ 18,953	$ 57,057	$ 351,436
Basic and diluted earnings per common unit:
As reported net income per common unit (in dollars per share)	$ 0.50	$ 1	$ 4.10
Pro forma net income per common unit (in dollars per share)	0.16	0.50	3.41
Pro forma net income per common unit, dilutive (in dollars per share)	$ 0.16	$ 0.50	$ 3.33
Enterprise Offshore Acquisition [Member]
Pro forma consolidated financial operating results:
Revenues			$ 2,421,989
Net Income Attributable to Genesis Energy, L.P.			$ 425,363
Basic and diluted earnings per common unit:
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax			$ 4.09
Business Acquisition, Pro Forma Earnings Per Unit, Basic And Diluted			$ 3.91

Receivables (Schedule of Trade

Receivables (Schedule of Trade Accounts Receivables Net) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable, Net, Current [Abstract]
Accounts receivable - trade	$ 503,917	$ 231,187
Allowance for doubtful accounts	(8,468)	(6,505)	$ (1,446)	$ (2,973)
Accounts receivable - trade, net	$ 495,449	$ 224,682

Receivables (Schedule of Allowa

Receivables (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance at beginning of period	$ 6,505	$ 1,446	$ 2,973
Charged to costs and expenses	2,001	6,463	1,242
Amounts written off	(38)	(1,404)	(2,769)
Balance at end of period	$ 8,468	$ 6,505	$ 1,446

Inventories (Schedule of Major

Inventories (Schedule of Major Components of Inventories) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Petroleum products	$ 8,731,000	$ 11,550,000
Crude oil	29,873,000	73,133,000
Caustic soda	5,755,000	4,593,000
NaHS	8,277,000	9,304,000
Raw materials - Alkali Operations	4,550,000	0
Work-in-process - Alkali Operations	7,355,000	0
Finished goods, net - Alkali Operations	14,075,000	0
Materials and supplies, net - Alkali Operations	10,030,000	0
Other	7,000	7,000
Total	88,653,000	98,587,000
Inventory write-down	$ 0	$ 0

Fixed Assets and Asset Retire64

Fixed Assets and Asset Retirement Obligations - (Schedule of Fixed Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 5,601,015	$ 4,763,396
Less: Accumulated depreciation	(734,986)	(548,532)
Net fixed assets	4,866,029	4,214,864
Crude oil pipelines and natural gas pipelines and related assets
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	3,028,657	2,901,202
Onshore facilities, machinery, and equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	692,364	427,658
Onshore facilities, machinery, and equipment | Alkali Business [Member]
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	497,601	0
Transportation equipment
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	21,483	17,543
Marine vessels
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	918,953	863,199
Land, buildings and improvements
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	223,186	55,712
Office equipment, furniture and fixtures
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	18,112	9,654
Construction in progress
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	151,768	440,225
Other
Property, Plant and Equipment [Line Items]
Fixed assets, at cost	$ 48,891	$ 48,203

Fixed Assets and Asset Retire65

Fixed Assets and Asset Retirement Obligations - (Schedule of Mineral Leaseholds) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Mineral leaseholds	$ 566,019
Less: Accumulated depletion	(1,513)
Mineral leaseholds, net	$ 564,506	$ 0

Fixed Assets and Asset Retire66

Fixed Assets and Asset Retirement Obligations (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations Details [Line Items]
Depreciation expense	$ 226,000,000	$ 194,000,000	$ 124,200,000
Depletion	1,500,000	0	0
Gain on sales of assets	40,311,000	0	0
Asset retirement obligation	198,187,000	213,726,000	$ 188,662,000
Accrued Liabilities [Member]
Asset Retirement Obligations Details [Line Items]
Asset retirement obligation	$ 20,900,000	$ 22,400,000

Fixed Assets and Asset Retire67

Fixed Assets and Asset Retirement Obligations - (Schedule of Reconciliation of Liability for Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 213,726	$ 188,662
AROs arising from the acquisition and consolidation of a previously held equity method investment		20,940
Accretion expense	11,008	10,800
Revisions in timing and estimated costs of AROs	7,146	(2,254)
Acquisitions	131
Divestitures	(7,649)
Settlements	(26,415)	(4,422)
Other	240
Asset retirement obligations, ending balance	$ 198,187	$ 213,726

Fixed Assets and Asset Retire68

Fixed Assets and Asset Retirement Obligations - (Forecast of Accretion Expense) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Forecast of Future Accretion Expense [Abstract]
2,018	$ 10,799
2,019	9,760
2,020	9,429
2,021	10,069
2,022	$ 10,753

Net Investment in Direct Fina69

Net Investment in Direct Financing Leases (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Leases [Abstract]
Fixed lease payments per year	$ 20.7
Fixed lease interest rate per year	10.25%
Minimum lease payments to be received in 2018	$ 20.7
Minimum lease payments to be received in 2019	20.7
Minimum lease payments to be received in 2020	20.7
Minimum lease payments to be received in 2021	20.7
Minimum lease payments to be received in 2022	$ 20.7

Net Investment in Direct Fina70

Net Investment in Direct Financing Leases (Components of Net Investment in Direct Financing Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Leases [Abstract]
Total minimum lease payments to be received	$ 215,884	$ 236,495
Unamortized initial direct costs	950	1,107
Less unearned income	(83,918)	(97,822)
Net investment in direct financing leases	132,916	139,780
Less current portion (included in other current assets)	(7,633)	(6,921)
Long-term portion of net investment in direct financing leases	$ 125,283	$ 132,859

Equity Investees (Narrative) (D

Equity Investees (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Apr. 01, 2016	Mar. 31, 2016	Jul. 25, 2015	Jul. 24, 2015	Jul. 23, 2015
Schedule of Equity Method Investments [Line Items]
Unamortized excess cost amount	$ 382,400	$ 398,100
Gain on basis step up on historical interest	$ 0	$ 0	$ 332,380
SEKCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage						50.00%
Poseidon Oil Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage	64.00%
Neptune Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage	25.70%
Enterprise Offshore Acquisition [Member]
Schedule of Equity Method Investments [Line Items]
Gain on basis step up on historical interest			$ 332,380
Transaction costs related to business acquisition							$ 1,500,000
Enterprise Offshore Acquisition [Member] | CHOPS [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest step up acquired percentage			50.00%				100.00%	50.00%
Equity investment, ownership percentage			50.00%				50.00%	50.00%
Enterprise Offshore Acquisition [Member] | SEKCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest step up acquired percentage			50.00%				100.00%	50.00%
Equity investment, ownership percentage			50.00%				50.00%	50.00%
Enterprise Offshore Acquisition [Member] | CHOPS and SEKCO
Schedule of Equity Method Investments [Line Items]
Gain on basis step up on historical interest			$ 332,400
Enterprise Offshore Acquisition [Member] | Poseidon Oil Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest step up acquired percentage							64.00%	28.00%
Equity investment, ownership percentage							36.00%
Enterprise Offshore Acquisition [Member] | Deepwater Gateway LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest step up acquired percentage				100.00%	50.00%
Equity investment, ownership percentage							50.00%
Transaction costs related to business acquisition					$ 26,000
Enterprise Offshore Acquisition [Member] | Neptune Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage							25.70%

Equity Investees (Consolidated

Equity Investees (Consolidated Financial Statements Related to Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Genesis’ share of operating earnings	$ 66,814	$ 63,805	$ 17,157
Amortization of differences attributable to Genesis' carrying value of equity investments	(15,768)	(15,861)	37,293
Net equity in earnings	51,046	47,944	54,450
Distributions received	$ 82,898	$ 87,220	$ 97,468

Equity Investees (Schedule of B

Equity Investees (Schedule of Balance Sheet Information for Equity Investees) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Current assets	$ 34,381	$ 35,375
Fixed assets, net	362,214	365,563
Other assets	14,927	3,177
Total assets	411,522	404,115
Liabilities and equity
Current liabilities	23,289	23,928
Other liabilities	249,610	230,327
Equity	138,623	149,860
Total liabilities and equity	$ 411,522	$ 404,115

Equity Investees (Schedule of O

Equity Investees (Schedule of Operations for Equity Investees) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 191,078	$ 193,038	$ 189,941
Operating Income	139,604	122,836	12,191
Net Income	$ 134,479	$ 118,175	$ 7,810

Intangible Assets, Goodwill a75

Intangible Assets, Goodwill and Other Assets (Schedule of Intangible Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 396,823	$ 395,692
Accumulated Amortization	214,417	190,805
Carrying Value	$ 182,406	204,887
Other
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 28,900	28,569
Accumulated Amortization	13,483	10,622
Carrying Value	15,417	17,947
Sodium Minerals and Sulfur Services
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	134,132	133,332
Accumulated Amortization	129,110	123,960
Carrying Value	$ 5,022	9,372
Sodium Minerals and Sulfur Services | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 94,654	94,654
Accumulated Amortization	92,493	89,756
Carrying Value	$ 2,161	4,898
Sodium Minerals and Sulfur Services | Licensing agreements
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	6 years
Gross Carrying Amount	$ 38,678	38,678
Accumulated Amortization	36,528	34,204
Carrying Value	$ 2,150	4,474
Sodium Minerals and Sulfur Services | Non-compete agreement
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	3 years
Gross Carrying Amount	$ 800	0
Accumulated Amortization	89	0
Carrying Value	711	0
Onshore Facilities and Transportation
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	48,690	48,690
Accumulated Amortization	40,015	38,135
Carrying Value	$ 8,675	10,555
Onshore Facilities and Transportation | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 35,430	35,430
Accumulated Amortization	35,082	33,676
Carrying Value	$ 348	1,754
Onshore Facilities and Transportation | Intangibles associated with lease
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	15 years
Gross Carrying Amount	$ 13,260	13,260
Accumulated Amortization	4,933	4,459
Carrying Value	$ 8,327	8,801
Marine Transportation
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	5 years
Gross Carrying Amount	$ 27,000	27,000
Accumulated Amortization	11,700	6,300
Carrying Value	$ 15,300	20,700
Offshore Pipeline Transportation
Finite-Lived Intangible Assets [Line Items]
Weighted Amortization Period in Years	19 years
Gross Carrying Amount	$ 158,101	158,101
Accumulated Amortization	20,109	11,788
Carrying Value	$ 137,992	$ 146,313

Intangible Assets, Goodwill a76

Intangible Assets, Goodwill and Other Assets (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Intangible Assets, Goodwill And Other Assets [Line Items]
Amortization of expense of intangible assets	$ 23,600,000	$ 24,300,000	$ 20,000,000
Goodwill	325,046,000	325,046,000
Impairment of goodwill	0	0	0
Amortization of CO2 assets	1,300,000	3,900,000	5,900,000
Sodium Minerals and Sulfur Services
Intangible Assets, Goodwill And Other Assets [Line Items]
Goodwill	301,900,000	301,900,000
Impairment of goodwill	0	0	0
Onshore Facilities and Transportation
Intangible Assets, Goodwill And Other Assets [Line Items]
Goodwill	23,100,000	23,100,000
Impairment of goodwill	$ 0	$ 0	$ 0

Intangible Assets, Goodwill a77

Intangible Assets, Goodwill and Other Assets (Schedule of Estimated Amortization Expense) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Finite-Lived Intangible Assets [Line Items]
2,018	$ 21,788
2,019	17,453
2,020	16,431
2,021	10,642
2,022	10,482
Other
Finite-Lived Intangible Assets [Line Items]
2,018	2,974
2,019	2,952
2,020	2,921
2,021	1,810
2,022	1,652
Sodium Minerals and Sulfur Services | Customer relationships
Finite-Lived Intangible Assets [Line Items]
2,018	2,161
2,019	0
2,020	0
2,021	0
2,022	0
Sodium Minerals and Sulfur Services | Licensing agreements
Finite-Lived Intangible Assets [Line Items]
2,018	2,150
2,019	0
2,020	0
2,021	0
2,022	0
Sodium Minerals and Sulfur Services | Non-compete agreement
Finite-Lived Intangible Assets [Line Items]
2,018	267
2,019	267
2,020	177
2,021	0
2,022	0
Onshore Facilities and Transportation | Customer relationships
Finite-Lived Intangible Assets [Line Items]
2,018	41
2,019	39
2,020	38
2,021	37
2,022	35
Onshore Facilities and Transportation | Intangibles associated with lease
Finite-Lived Intangible Assets [Line Items]
2,018	474
2,019	474
2,020	474
2,021	474
2,022	474
Marine Transportation
Finite-Lived Intangible Assets [Line Items]
2,018	5,400
2,019	5,400
2,020	4,500
2,021	0
2,022	0
Offshore Pipeline Transportation
Finite-Lived Intangible Assets [Line Items]
2,018	8,321
2,019	8,321
2,020	8,321
2,021	8,321
2,022	$ 8,321

Intangible Assets, Goodwill a78

Intangible Assets, Goodwill and Other Assets (Schedule of Other Assets) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
CO2 volumetric production payments, net of amortization		$ 2,175	$ 3,503
Deferred marine charges, net	[1]	30,246	27,710
Other deferred costs and deposits		24,207	25,398
Other assets, net of amortization		$ 56,628	$ 56,611
[1]	(1)See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2)

Debt (Schedule of Obligations U

Debt (Schedule of Obligations Under Debt Arrangements) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 11, 2017	Dec. 31, 2016	Jul. 23, 2015	May 21, 2015	May 15, 2014	Feb. 08, 2013	Feb. 01, 2012
Debt Instrument [Line Items]
Senior secured credit facilities	$ 1,099,200		$ 1,278,200
Unamortized discount an debt issuance costs	46,252		36,831
Senior unsecured notes	2,598,918		1,813,169
Long-term debt, principal	3,744,370		3,128,200
Total long-term debt, net value	3,698,118		3,091,369
5.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	145,170		350,000				$ 350,000
Unamortized discount an debt issuance costs	1,303		4,163
Senior unsecured notes	143,867		345,837
6.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	750,000		750,000	$ 750,000
Unamortized discount an debt issuance costs	16,077		19,296
Senior unsecured notes	733,923		730,704
6.000% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	400,000		400,000		$ 400,000			$ 350,000
Unamortized discount an debt issuance costs	5,691		6,758
Senior unsecured notes	394,309		393,242
5.625% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	350,000		350,000			$ 350,000
Unamortized discount an debt issuance costs	5,717		6,614
Senior unsecured notes	344,283		343,386
6.500% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	550,000		0
Unamortized discount an debt issuance costs	9,462		0
Senior unsecured notes	540,538		0
6.250% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	450,000	$ 450,000	0
Unamortized discount an debt issuance costs	8,002		0
Senior unsecured notes	441,998		0
Credit Facility [Domain]
Debt Instrument [Line Items]
Unamortized discount an debt issuance costs	$ 0		$ 0

Debt (Senior Secured Credit Fac

Debt (Senior Secured Credit Facility) (Details)	12 Months Ended
	Dec. 31, 2017USD ($)
Amended Facility [Member] | Accordion [Member]
Debt Instrument [Line Items]
Credit facility aggregate maximum borrowing capacity	$ 2,000,000,000
Senior Secured Credit Facility [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Senior secured credit facility, amount outstanding	$ 1,099,200,000
Total amount available for borrowings, remaining borrowing capacity	599,800,000
Senior Secured Credit Facility [Member] | Petroleum Products [Member]
Debt Instrument [Line Items]
Senior secured credit facility, amount outstanding	$ 29,000,000
Senior Secured Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Debt instrument covenant, requirement leverage ratio	1
Debt instrument covenant, requirement senior secured leverage ratio	1
Debt instrument covenant, requirement interest coverage ratio	1
Senior Secured Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.25%
Debt instrument covenant, requirement leverage ratio	5.75
Debt instrument covenant, requirement senior secured leverage ratio	3.75
Debt instrument covenant, requirement interest coverage ratio	3
Senior Secured Credit Facility [Member] | Acquisition Period | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument covenant, requirement interest coverage ratio	1
Senior Secured Credit Facility [Member] | Acquisition Period | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument covenant, requirement interest coverage ratio	2.75
Senior Secured Credit Facility [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Letter of credit, fee percentage	2.75%
Letters of credit, outstanding amount	$ 1,000,000
Senior Secured Credit Facility [Member] | Letter of Credit [Member] | Maximum [Member]
Debt Instrument [Line Items]
Letters of credit, outstanding amount	100,000,000
Senior Secured Credit Facility [Member] | Amended Facility [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	1,700,000,000
Senior Secured Credit Facility [Member] | Amended Facility [Member] | Accordion [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	$ 300,000,000
Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	0.50%
Federal Funds Effective Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.00%
LIBOR Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.00%
Eurodollar Rate [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	2.75%
Eurodollar Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.50%
Letter of credit, fee percentage	3.00%
Eurodollar Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	3.00%
Letter of credit, fee percentage	1.50%
Alternate Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Letter of credit, fee percentage	2.00%
Alternate Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Letter of credit, fee percentage	0.50%
Applicable Margin [Member]
Debt Instrument [Line Items]
Interest rate spreads senior secured credit facility	1.75%

Debt (Senior Unsecured Notes) (

Debt (Senior Unsecured Notes) (Details) - USD ($)	Dec. 11, 2017	Sep. 01, 2017	Aug. 14, 2017	Jul. 23, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 31, 2015	May 21, 2015	May 15, 2014	Feb. 08, 2013	Feb. 01, 2012
Debt Instrument [Line Items]
Loss on extinguishment of debt					$ 6,242,000	$ 0	$ 19,225,000
Proceeds from issuance of unsecured debt					1,000,000,000	0	1,139,718,000
Enterprise Offshore Acquisition [Member]
Debt Instrument [Line Items]
Senior unsecured notes, principal								$ 750,000,000
5.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal					145,170,000	350,000,000					$ 350,000,000
Debt instrument, stated rate											5.75%
Proceeds used to repay unsecured debt principal	$ 204,800,000
6.250% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal	$ 450,000,000				450,000,000	0
Debt instrument, stated rate	6.25%
Proceeds from issuance of debt, net of discount	$ 442,000,000
5.625% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal					350,000,000	350,000,000				$ 350,000,000
Debt instrument, stated rate										5.625%
6.000% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal					400,000,000	400,000,000			$ 400,000,000			$ 350,000,000
Debt instrument, stated rate									6.00%
7.875% Senior Unsecured Notes
Debt Instrument [Line Items]
Debt instrument, stated rate												7.875%
Note tender offer							300,100,000
Redemption premium							49,900,000
Loss on extinguishment of debt							$ 19,200,000
6.750% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal				$ 750,000,000	750,000,000	750,000,000
6.750% senior unsecured notes | Enterprise Offshore Acquisition [Member]
Debt Instrument [Line Items]
Debt instrument, stated rate				6.75%
Proceeds from issuance of debt, net of discount				$ 728,600,000
6.500% senior unsecured notes
Debt Instrument [Line Items]
Senior unsecured notes, principal					$ 550,000,000	$ 0
6.500% senior unsecured notes | Alkali Business [Member]
Debt Instrument [Line Items]
Senior unsecured notes, principal		$ 550,000,000	$ 550,000,000
Debt instrument, stated rate		6.50%	6.50%
Proceeds from issuance of debt, net of discount		$ 540,100,000
Proceeds from issuance of unsecured debt			$ 540,100,000

Debt (Redemption Periods Senior

Debt (Redemption Periods Senior Unsecured Notes) (Details)	12 Months Ended
	Dec. 31, 2017
2021 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2022 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2023 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2024 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2025 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%
2026 Notes
Debt Instrument [Line Items]
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to	35.00%

Partners' Capital, Mezzanine 83

Partners' Capital, Mezzanine and Equity Distributions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 24, 2017	Jul. 27, 2016	Jul. 22, 2015	Apr. 10, 2015	Dec. 31, 2017	Dec. 31, 2016
Partners Capital And Distributions [Line Items]
Common units outstanding (in shares)					122,579,218	117,979,218
Cash or stock available for distributions, percent usually distributed					100.00%
Days to distribute					45 days
Common units issued (in shares)					122,579,218	117,979,218
Price per share of common units issued (in dollars per share)	$ 30.65	$ 37.90	$ 43.77	$ 44.42
Net proceeds received from sale of units, net of underwriter discounts	$ 140,513	$ 298,452	$ 437,164	$ 198,168
Class A [Member]
Partners Capital And Distributions [Line Items]
Common units issued (in shares)	4,600,000	8,000,000	10,350,000	4,600,000
Price per share of common units issued (in dollars per share)	$ 30.65	$ 37.90	$ 43.77	$ 44.42
Additional common units to purchase (in shares)	600,000		1,350,000	600,000
Net proceeds received from sale of units, net of underwriter discounts	$ 140,500	$ 298,000	$ 437,200	$ 198,200
Class A [Member] | Partners' Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in shares)					122,539,221
Class B [Member] | Partners' Capital
Partners Capital And Distributions [Line Items]
Common units outstanding (in shares)					39,997

Partners' Capital, Mezzanine 84

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

Feb. 14, 2018

Nov. 14, 2017

Aug. 14, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Dec. 31, 2017

[1]

Sep. 30, 2017

[1]

Jun. 30, 2017

[1]

Mar. 31, 2017

[1]

Dec. 31, 2016

[1]

Sep. 30, 2016

[1]

Jun. 30, 2016

[1]

Mar. 31, 2016

[1]

Distribution Made to Limited Partner [Line Items]

Date Paid

Nov. 14, 2017

Aug. 14, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Per Unit Amount (in dollars per share)

$ 0.5000

$ 0.7225

$ 0.7200

$ 0.7100

$ 0.7000

$ 0.6900

$ 0.6725

$ 0.6550

$ 0.5000

$ 0.7225

$ 0.7200

$ 0.7100

$ 0.7000

$ 0.6900

$ 0.6725

$ 0.6550

Total Amount

$ 61,290

$ 88,563

$ 88,257

$ 83,765

$ 82,585

$ 81,406

$ 73,961

$ 72,036

Subsequent Event [Member]

Distribution Made to Limited Partner [Line Items]

Date Paid

Feb. 14, 2018

Per Unit Amount (in dollars per share)

$ 0.5100

Total Amount

$ 62,515

[1]

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

Partners' Capital, Mezzanine 85

Partners' Capital, Mezzanine and Equity Distributions (New Common Units Issued To The Public For Cash) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 24, 2017	Jul. 27, 2016	Jul. 22, 2015	Apr. 10, 2015
Equity [Abstract]
Units (in shares)	4,600	8,000	10,350	4,600
Gross Unit Price (in dollars per share)	$ 30.65	$ 37.90	$ 43.77	$ 44.42
Issuance Value	$ 140,990	$ 303,200	$ 453,020	$ 204,332
Costs	(477)	(4,748)	(15,856)	(6,164)
Net Proceeds	$ 140,513	$ 298,452	$ 437,164	$ 198,168

Partners' Capital, Mezzanine 86

Partners' Capital, Mezzanine and Equity Distributions (Class A Convertible Preferred Units Narrative) (Details) $ / shares in Units, $ in Thousands	Sep. 01, 2024USD ($)directorshares	Sep. 01, 2022	Mar. 01, 2019quarter	Feb. 14, 2018$ / sharesshares	Sep. 01, 2017USD ($)$ / sharesshares	Dec. 31, 2017USD ($)shares	Dec. 31, 2017USD ($)shares	Sep. 01, 2019USD ($)
Temporary Equity [Line Items]
Class A convertible preferred units issued (in shares)						22,411,728	22,411,728
Distribution paid-in-kind (in shares)							162,234
Accumulated distributions to preferred unitholders | $						$ 22,000	$ 22,000
Convertible Preferred Stock [Member]
Temporary Equity [Line Items]
Temporary Equity, Distributions | $						$ 5,500
Temporary Equity, Stock Issued During Period, Value, New Issues | $					$ 750,000
Temporary Equity, Number of Shares Authorized To Be Converted					7,416,498
Temporary Equity, Consecutive Period For Shares To be Converted					12 months
Temporary Equity, Minimum Number of Shares Outstanding Authorized To Be Converted					592,768
Temporary Equity, Volume Weighted Average Price Percentage					95.00%
Temporary Equity, Consideration Payable To Holders In Cash For Change Of Control, Percentage					90.00%
Temporary Equity, Threshold Trading Days To Notify Holders					30 days
Temporary Equity, Consecutive Trading Days In Period Ending On Fifth Trading Day					30 days
Temporary Equity, Change in Control Multiplier Price Percentage					101.00%
Temporary Equity, Percentage of Distribution Paid-in-kind						100.00%
Distribution paid-in-kind (in shares)							162,234
Accumulated distributions to preferred unitholders | $						$ 22,000	$ 22,000
Convertible Preferred Stock [Member] | In Arrears At Annual Rate [Member]
Temporary Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage					8.75%
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ / shares					$ 2.9496
Convertible Preferred Stock [Member] | Quarterly Rate [Member]
Temporary Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage					2.1875%
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ / shares					$ 0.7374
Convertible Preferred Stock [Member] | Scenario, Forecast [Member]
Temporary Equity [Line Items]
Temporary Equity, Threshold Trading Days To Notify Holders		30 days
Basis spread			2
Reset rate		10.75%
Percentage below issue price		110.00%
Temporary Equity, Percentage of Holders Required to Approve Rate Reset Election		25.00%
Temporary Equity, Multiplier Liquidation Value Percentage One	110.00%
Temporary Equity, Multiplier Liquidation Value Percentage Two	105.00%
Temporary Equity, Conversion Ratio	1
Temporary Equity, Aggregate Amount Of Conversion Required, Minimum | $								$ 50,000
Temporary Equity, Number of Quarters In Trading Period | quarter			2
Temporary Equity, Aggregate Amount Of Ownership Required For Initial Purchasers To Attend Board Meetings | $	$ 200,000
Temporary Equity, Percentage Required For Initial Purchasers To Purchase Securities	50.00%
Temporary Equity, Aggregate Number of Ownership Units Required For Initial Purchasers To Appoint Directors	11,124,747
Temporary Equity, Number of Directors That Initial Purchasers Have Right To Appoint | director	2
Convertible Preferred Stock [Member] | Minimum [Member]
Temporary Equity [Line Items]
Temporary Equity, Redemption Premium Percentage					115.00%
Convertible Preferred Stock [Member] | Maximum [Member]
Temporary Equity [Line Items]
Temporary Equity, Redemption Premium Percentage					101.00%
Convertible Preferred Stock [Member] | London Interbank Offered Rate (LIBOR) [Member] | Scenario, Forecast [Member]
Temporary Equity [Line Items]
Basis spread		0.0750
Private Placement [Member] | Convertible Preferred Stock [Member]
Temporary Equity [Line Items]
Temporary Equity, Stock Issued During Period, Value, New Issues | $					$ 750,000
Class A convertible preferred units issued (in shares)					22,249,494	22,411,728	22,411,728
Temporary Equity, Per Share Price | $ / shares					$ 33.71
Temporary Equity, Number of Initial Purchasers					2
Subsequent Event [Member] | Convertible Preferred Stock [Member]
Temporary Equity [Line Items]
Distribution paid-in-kind (in shares)				490,252
Subsequent Event [Member] | Convertible Preferred Stock [Member] | In Arrears At Annual Rate [Member]
Temporary Equity [Line Items]
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ / shares				$ 2.9496
Subsequent Event [Member] | Convertible Preferred Stock [Member] | Quarterly Rate [Member]
Temporary Equity [Line Items]
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ / shares				$ 0.7374

Partners' Capital, Mezzanine 87

Partners' Capital, Mezzanine and Equity Distributions (Initial Measurement of Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	Sep. 01, 2017	Dec. 31, 2017	Dec. 31, 2016
Temporary Equity [Line Items]
Transaction price, net		$ 697,151	$ 0
Class A Convertible Preferred Stock Units [Member]
Temporary Equity [Line Items]
Transaction price, gross	$ 750,000
Transaction cost to other third parties	(23,581)
Transaction price, net	726,419	726,419
Preferred Units, net	691,969
Preferred Distribution Rate Reset Election (Note 18)	34,450
Transaction price, net	$ 726,419	$ 697,151	$ 0

Partners' Capital, Mezzanine 88

Partners' Capital, Mezzanine and Equity Distributions (Change in Class A Convertible Preferred Units) (Details) - USD ($) $ in Thousands	Sep. 01, 2017	Dec. 31, 2017
Carrying Amount
Beginning Balance		$ 0
Ending Balance		$ 697,151
Units
Beginning Balance (in shares)		0
Issuance of Preferred Units (in shares)		22,249,494
Distribution paid-in-kind (in shares)		162,234
Ending Balance (in shares)		22,411,728
Class A Convertible Preferred Stock Units [Member]
Carrying Amount
Beginning Balance		$ 0
Issuance of Preferred Units, net	$ 726,419	726,419
Allocation to Preferred Distribution Rate Reset Election		(34,450)
Distribution paid-in-kind		5,469
Allocation of Distribution paid-kind to Preferred Distribution Rate Reset Election		(287)
Ending Balance	$ 726,419	$ 697,151
Units
Distribution paid-in-kind (in shares)		162,234

Net Income Per Common Unit (Det

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 01, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Class A convertible preferred units issued (in shares)	22,411,728								22,411,728
Net Income Attributable to Genesis Energy L.P.	$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ 22,118	$ 32,101	$ 23,727	$ 35,303	$ 82,647	$ 113,249	$ 422,528
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(21,995)	0	0
Net Income Available to Common Unitholders									$ 60,652	$ 113,249	$ 422,528
Weighted Average Outstanding Units (in units)									121,546,000	113,433,000	103,004,000
Basic and Diluted (in dollars per unit)									$ 0.50	$ 1	$ 4.10
Private Placement [Member] | Convertible Preferred Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Class A convertible preferred units issued (in shares)	22,411,728								22,411,728			22,249,494
Alkali Business [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Basic and Diluted (in dollars per unit)									$ 0.50	$ 1	$ 4.10

Business Segment Information (S

Business Segment Information (Schedule of Revenues by Segment) (Details) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jul. 25, 2015	Jul. 24, 2015	Jul. 23, 2015
Segment Reporting [Abstract]
Number of operating segments | segment										4
Segment Reporting Information [Line Items]
Total Segment Margin	[1]									$ 594,543	$ 569,571	$ 476,585
Capital Expenditures	[2]									1,580,821	443,993	2,007,611
External Customers										2,028,377	1,712,493	2,246,529
Intersegment	[3]									0	0	0
Total revenues		$ 720,049	$ 486,114	$ 406,723	$ 415,491	$ 428,053	$ 460,050	$ 445,976	$ 378,414	2,028,377	1,712,493	$ 2,246,529
SEKCO [Member]
Segment Reporting Information [Line Items]
Equity investment, ownership percentage													50.00%
Enterprise Offshore Acquisition [Member] | Deepwater Gateway LLC [Member]
Segment Reporting Information [Line Items]
Equity investment, ownership percentage														50.00%
Enterprise Offshore Acquisition [Member] | SEKCO [Member]
Segment Reporting Information [Line Items]
Equity investment, ownership percentage												50.00%		50.00%	50.00%
Enterprise Offshore Acquisition [Member] | SEKCO [Member] | Co-venturer [Member] | Enterprise [Member]
Segment Reporting Information [Line Items]
Equity investment, ownership percentage													50.00%
Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Total revenues										318,239	334,679	$ 140,230
Offshore Pipeline Transportation | Deepwater Gateway LLC [Member]
Segment Reporting Information [Line Items]
Capital Expenditures											35,100
Offshore Pipeline Transportation | SEKCO [Member]
Segment Reporting Information [Line Items]
Capital Expenditures												2,500
Offshore Pipeline Transportation | Enterprise Offshore Acquisition [Member]
Segment Reporting Information [Line Items]
Capital Expenditures	[3]											1,500,000
Sodium Minerals and Sulfur Services
Segment Reporting Information [Line Items]
Total revenues										462,622	171,503	177,880
Sodium Minerals and Sulfur Services | Alkali Business [Member]
Segment Reporting Information [Line Items]
Capital Expenditures										1,300,000
Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Total revenues										1,042,229	993,290	1,689,662
Marine Transportation
Segment Reporting Information [Line Items]
Total revenues										205,287	213,021	238,757
Operating Segments [Member] | Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	[1]									317,540	336,620	197,723
Capital Expenditures	[2]									8,815	46,277	1,527,320
External Customers										319,455	332,514	140,230
Operating Segments [Member] | Sodium Minerals and Sulfur Services
Segment Reporting Information [Line Items]
Total Segment Margin	[1]									130,333	79,508	80,246
Capital Expenditures	[2]									1,354,469	2,274	1,595
External Customers										470,789	180,665	187,257
Operating Segments [Member] | Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	[1]									96,376	83,364	95,394
Capital Expenditures	[2]									149,123	316,638	409,687
External Customers	[1]									1,044,083	993,103	1,688,850
Operating Segments [Member] | Marine Transportation
Segment Reporting Information [Line Items]
Total Segment Margin	[1]									50,294	70,079	103,222
Capital Expenditures	[2]									68,414	78,804	69,009
External Customers										194,050	206,211	230,192
Intersegment Eliminations [Member] | Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
Intersegment	[3]									(1,216)	2,165	0
Intersegment Eliminations [Member] | Sodium Minerals and Sulfur Services
Segment Reporting Information [Line Items]
Intersegment	[3]									(8,167)	(9,162)	(9,377)
Intersegment Eliminations [Member] | Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
Intersegment	[3]									(1,854)	187	812
Intersegment Eliminations [Member] | Marine Transportation
Segment Reporting Information [Line Items]
Intersegment	[3]									$ 11,237	$ 6,810	$ 8,565
[1]	A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. 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 acquisitions of businesses and contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our sodium minerals and sulfur services segment included $1.3 billion during the year ended December 31, 2017 related to the acquisition of our Alkali Business. During the year ended December 31, 2016, capital expenditures in our offshore pipeline transportation segment included $35.1 million related to the acquisition of the remaining 50% ownership in Deepwater Gateway. Additionally, in 2015, there was $1.5 billion in capital spending to fund our Enterprise acquisition. Capital spending in this segment also included $2.5 million during the year ended December 31, 2015 representing capital contributions to our SEKCO pipeline to fund our share of the construction costs for its pipeline (as prior to our Enterprise acquisition in July 2015, we owned a 50% interest in the SEKCO pipeline with Enterprise owning the remaining 50%).
[3]	Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.

Business Segment Information 91

Business Segment Information (Schedule of Total Assets By Reportable Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 7,137,481	$ 5,702,592	$ 5,459,599
Other assets
Segment Reporting Information [Line Items]
TOTAL ASSETS	49,737	43,089	48,208
Offshore Pipeline Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	2,486,803	2,575,335	2,623,478
Sodium Minerals and Sulfur Services
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,848,188	395,043	394,626
Onshore Facilities and Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	1,927,976	1,875,403	1,615,335
Marine Transportation
Segment Reporting Information [Line Items]
TOTAL ASSETS	$ 824,777	$ 813,722	$ 777,952

Business Segment Information (R

Business Segment Information (Reconciliation of Segment Margin To Net Income) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting [Abstract]
Total Segment Margin	[1]									$ 594,543	$ 569,571	$ 476,585
Corporate general and administrative expenses										(60,029)	(40,905)	(61,370)
Depreciation, depletion, amortization and accretion										(262,021)	(230,563)	(155,081)
Interest expense										(176,762)	(139,947)	(100,596)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income	[2]									(31,852)	(39,276)	(43,018)
Non-cash items not included in Segment Margin										(14,305)	(3,221)	2,809
Cash payments from direct financing leases in excess of earnings										(6,921)	(6,277)	(5,685)
Gain on basis step up on historical interest										0	0	332,380
Loss on debt extinguishment										(6,242)	0	(19,225)
Differences in Timing of Cash Receipts for Certain Contractual Arrangement	[3]									17,540	13,253	6,359
Gain on sales of assets										40,311	0	0
Other, net										(2,985)	(6,044)	(6,643)
Non-cash provision for leased items no longer in use										(12,589)	0	0
Income tax benefit (expense)										3,959	(3,342)	(3,987)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.		$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ 22,118	$ 32,101	$ 23,727	$ 35,303	$ 82,647	$ 113,249	$ 422,528
[1]	A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for each year is presented below.
[2]	Includes distributions attributable to the period and received during or promptly following such period.
[3]	Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

Transactions with Related Par93

Transactions with Related Parties (Schedule of Transactions With Related Parties) (Details) - USD ($) $ in Thousands		4 Months Ended	12 Months Ended
		Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sandhill Group Llc [Member]
Related Party Transaction [Line Items]
Equity investment, ownership percentage		50.00%	50.00%
Poseidon Oil Pipeline Company [Member]
Related Party Transaction [Line Items]
Equity investment, ownership percentage		64.00%	64.00%
Sandhill Group Llc [Member]
Related Party Transaction [Line Items]
Related party transaction, revenues	[1]		$ 2,820	$ 3,097	$ 3,259
Poseidon Oil Pipeline Company [Member]
Related Party Transaction [Line Items]
Related party transaction, revenues	[2]		12,357	10,844	4,536
Related party transaction, expenses	[2]		986	1,007	464
ANSAC [Member]
Related Party Transaction [Line Items]
Related party transaction, revenues		$ 124,500	124,536	0	0
Related party transaction, expenses		$ 2,200	2,242	0	0
Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Related party transaction, expenses			$ 660	$ 660	$ 690
[1]	We own a 50% interest in Sandhill Group, LLC.
[2]	We own a 64% interest in Poseidon Oil Pipeline Company, LLC.

Transactions with Related Par94

Transactions with Related Parties (Narrative) (Details) - USD ($) $ in Thousands		4 Months Ended	12 Months Ended
		Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Poseidon Oil Pipeline Company [Member]
Related Party Transaction [Line Items]
Due from related parties		$ 2,200	$ 2,200	$ 1,600
Management fees revenue			8,400	7,900	$ 3,900
Net sales from related party	[1]		12,357	10,844	4,536
Costs charged by related party, included in operating costs	[1]		986	1,007	464
ANSAC [Member]
Related Party Transaction [Line Items]
Due from related parties		74,490	74,490
Net sales from related party		124,500	124,536	0	0
Costs charged by related party, included in operating costs		$ 2,200	$ 2,242	$ 0	$ 0
[1]	We own a 64% interest in Poseidon Oil Pipeline Company, LLC.

Transactions with Related Par95

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

Supplemental Cash Flow Inform96

Supplemental Cash Flow Information (Net Changes In Components of Operating Assets And Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
(Increase) decrease in:
Accounts receivable	$ (140,948)	$ (9,859)	$ 99,384
Inventories	49,055	(54,361)	3,811
Deferred charges	(3,622)	(3,902)	(11,916)
Other current assets	(410)	3,059	6,417
Increase (decrease) in:
Accounts payable	97,569	(17,426)	(101,581)
Accrued liabilities	8,512	(8,161)	9,257
Net changes in components of operating assets and liabilities	$ 10,156	$ (90,650)	$ 5,372

Supplemental Cash Flow Inform97

Supplemental Cash Flow Information (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 25, 2015	Jul. 24, 2015	Jul. 23, 2015
Supplemental Cash Flow Elements [Abstract]
Payments of interest and commitment fees	$ 168,300	$ 157,400	$ 86,800
Capitalized interest	15,000	26,600	17,100
Cash paid for income taxes	1,000	1,300	900
Incurred liabilities for fixed and intangible asset additions	39,700	33,700	68,600
Schedule of Equity Method Investments [Line Items]
Gain on basis step up on historical interest	$ 0	$ 0	332,380
SEKCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage				50.00%
Enterprise Offshore Acquisition [Member]
Schedule of Equity Method Investments [Line Items]
Gain on basis step up on historical interest			$ 332,380
Enterprise Offshore Acquisition [Member] | CHOPS [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage			50.00%		50.00%	50.00%
Equity interest step up acquired percentage			50.00%		100.00%	50.00%
Enterprise Offshore Acquisition [Member] | SEKCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership percentage			50.00%		50.00%	50.00%
Equity interest step up acquired percentage			50.00%		100.00%	50.00%

Equity-Based Compensation Pla98

Equity-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ (4,577)	$ 8,580	$ 6,922
Service-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in shares)	102,868
Weighted average grant date fair value of phantom unit (in dollars per share)	$ 32.27
Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in shares)	194,346
Weighted average grant date fair value of phantom unit (in dollars per share)	$ 32.43
2010 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 2,100
Weighted average period of recognition, years	1 year 6 months
Compensation expense	$ (3,400)	8,900
Liability for compensation awards	$ 3,200	$ 13,600
2010 Long Term Incentive Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	150.00%
2010 Long Term Incentive Plan [Member] | Performance-Based and Service-Based Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in shares)	297,214	339,584
Weighted average grant date fair value of phantom unit (in dollars per share)	$ 32.37	$ 30.71
2010 Long Term Incentive Plan [Member] | Service-Based Awards | Anniversary Year 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Service-Based Awards | Anniversary Year 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Service-Based Awards | Anniversary Year 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	50.00%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage		150.00%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage		50.00%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards | Anniversary Year 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards | Anniversary Year 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Performance-Based Awards | Anniversary Year 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage	33.33%	33.33%
2010 Long Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units awarded during the period (in shares)			212,825
Weighted average grant date fair value of phantom unit (in dollars per share)			$ 44.95

Equity-Based Compensation Pla99

Equity-Based Compensation Plans (Summary of Service-Based And Performance-Based Awards) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Service-Based Awards
Number of Phantom Units
Unvested at December 31, 2016 (in shares) | shares	181,230
Granted (in shares) | shares	102,868
Forfeited (in shares) | shares	(3,402)
Settled (in shares) | shares	(40,859)
Unvested at December 31, 2017 (in shares) | shares	239,837
Average Grant Date Fair Value
Unvested at December 31, 2016 (in dollars per share) | $ / shares	$ 40.59
Granted (in dollars per share) | $ / shares	32.27
Forfeited (in dollars per share) | $ / shares	37.22
Settled (in dollars per share) | $ / shares	53.84
Unvested at December 31, 2017 (in dollars per share) | $ / shares	$ 34.81
Total Value (in thousands)
Unvested at December 31, 2016 | $	$ 7,356
Granted | $	3,320
Forfeited | $	(127)
Settled | $	(2,200)
Unvested at December 31, 2017 | $	$ 8,349
Performance-Based Awards
Number of Phantom Units
Unvested at December 31, 2016 (in shares) | shares	483,232
Granted (in shares) | shares	194,346
Forfeited (in shares) | shares	(17,410)
Settled (in shares) | shares	(77,793)
Unvested at December 31, 2017 (in shares) | shares	582,375
Average Grant Date Fair Value
Unvested at December 31, 2016 (in dollars per share) | $ / shares	$ 38.82
Granted (in dollars per share) | $ / shares	32.43
Forfeited (in dollars per share) | $ / shares	35.43
Settled (in dollars per share) | $ / shares	54.18
Unvested at December 31, 2017 (in dollars per share) | $ / shares	$ 34.73
Total Value (in thousands)
Unvested at December 31, 2016 | $	$ 18,757
Granted | $	6,303
Forfeited | $	(617)
Settled | $	(4,215)
Unvested at December 31, 2017 | $	$ 20,228

Equity-Based Compensation Pl100

Equity-Based Compensation Plans (Expense Related To Equity-Based Compensation Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ (4,577)	$ 8,580	$ 6,922
Onshore facilities and transportation operating costs
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	(1,137)	1,688	1,185
Marine transportation operating costs
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	(483)	1,089	851
Sodium minerals and sulfur services operating costs
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	(533)	547	227
Offshore pipeline operating costs
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	(152)	681	94
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expense related to equity-based compensation plan	$ (2,272)	$ 4,575	$ 4,565

Major Customers and Credit R101

Major Customers and Credit Risk (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Customer Concentration Risk [Member] | Supply And Logistics Revenues [Member] | Shell Oil Company [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	13.00%	12.00%	12.00%

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivatives Entered Into to Hedge Inventory or Fixed Price Purchase Commitments) (Details) bbl in Thousands	12 Months Ended
	Dec. 31, 2017bbl$ / bbl
Sell (Short) Contracts | Designated as Hedging Instrument [Member] | Futures [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	297
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	57.70
Sell (Short) Contracts | Not Designated As Hedging Instrument [Member] | Futures [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	223
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	56.86
Sell (Short) Contracts | Not Designated As Hedging Instrument [Member] | Futures [Member] | Fuel Oil Futures [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	260
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	55.01
Sell (Short) Contracts | Not Designated As Hedging Instrument [Member] | Options [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	80
Weighted average premium received (in dollars per barrel) | $ / bbl	0.85
Buy (Long) Contracts | Designated as Hedging Instrument [Member] | Futures [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	0
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	0
Buy (Long) Contracts | Not Designated As Hedging Instrument [Member] | Futures [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	152
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	57.30
Buy (Long) Contracts | Not Designated As Hedging Instrument [Member] | Futures [Member] | Fuel Oil Futures [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	20
Weighted average contract price per bbl (in dollars per barrel) | $ / bbl	53.20
Buy (Long) Contracts | Not Designated As Hedging Instrument [Member] | Options [Member] | Crude Oil [Member]
Derivative [Line Items]
Contract volumes (1,000 bbls) | bbl	45
Weighted average premium received (in dollars per barrel) | $ / bbl	0.24

Derivatives (Fair Value of Deri

Derivatives (Fair Value of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Liability Derivatives:
Preferred Distribution Rate Reset Election		$ (45,200)
Current Assets-Other [Member]
Asset Derivatives:
Total asset derivatives		0	$ 0
Embedded Derivative Financial Instruments [Member] | Other Noncurrent Liabilities [Member]
Liability Derivatives:
Preferred Distribution Rate Reset Election	[1]	(45,209)	0
Not Designated As Hedging Instrument [Member] | Commodity Derivatives [Member] | Current Assets-Other [Member]
Asset Derivatives:
Gross amount of recognized assets		505	443
Gross amount offset in the Consolidated Balance Sheets		(505)	(443)
Net amount of assets presented in the Consolidated Balance Sheets		0	0
Liability Derivatives:
Gross amount of recognized liabilities	[2]	(1,203)	(1,772)
Gross amount offset in the Consolidated Balance Sheets	[2]	1,203	1,772
Net amount of liabilities presented in the Consolidated Balance Sheets		0	0
Designated as Hedging Instrument [Member] | Commodity Derivatives [Member] | Current Assets-Other [Member]
Asset Derivatives:
Gross amount of recognized assets		54	3,321
Gross amount offset in the Consolidated Balance Sheets		(54)	(3,321)
Net amount of assets presented in the Consolidated Balance Sheets		0	0
Liability Derivatives:
Gross amount of recognized liabilities	[2]	(863)	(9,506)
Gross amount offset in the Consolidated Balance Sheets	[2]	338	7,589
Net amount of liabilities presented in the Consolidated Balance Sheets		$ (525)	$ (1,917)
[1]	Refer to Note 11 and Note 19 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.
[2]	These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other.

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 01, 2022	Mar. 01, 2019
Derivatives, Fair Value [Line Items]
Net broker receivables	$ 1	$ 5.6
Margin deposit assets	1.3	5.1
Increase (decrease) in variation margin deposits outstanding	(0.3)	$ 0.5
Fair value of embedded derivative liability	$ 45.2
Convertible Preferred Stock [Member] | Scenario, Forecast [Member]
Derivatives, Fair Value [Line Items]
Basis spread				2
Reset rate			10.75%
Percentage below issue price			110.00%
Convertible Preferred Stock [Member] | London Interbank Offered Rate (LIBOR) [Member] | Scenario, Forecast [Member]
Derivatives, Fair Value [Line Items]
Basis spread			0.0750

Derivatives (Effects on Consoli

Derivatives (Effects on Consolidated Statements of Operations and Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income		$ 3,802	$ (19,042)	$ 14,925
Embedded Derivative Financial Instruments [Member] | Other Expense
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income	$ (10,472)		0	0
Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income				(1,101)
Designated as Hedging Instrument [Member] | Commodity Derivatives [Member] | Onshore facilities and transportation product costs
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income		5,116	(13,195)
Not Designated As Hedging Instrument [Member] | Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income				$ 16,026
Not Designated As Hedging Instrument [Member] | Commodity Derivatives [Member] | Onshore facilities and transportation product costs
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives, amount of gain (loss) recognized in income		$ (1,314)	$ (5,847)

Fair-Value Measurements (Fair V

Fair-Value Measurements (Fair Value of Financial Assets Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets Fair Value	$ 559	$ 3,764
Liabilities Fair Value	(2,066)	(11,278)
Commodity Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets Fair Value	0	0
Liabilities Fair Value	0	0
Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets Fair Value	0	0
Liabilities Fair Value	0	0
Embedded Derivative Financial Instruments [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value	0	0
Embedded Derivative Financial Instruments [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value	0	0
Embedded Derivative Financial Instruments [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value	$ (45,209)	$ 0

Fair-Value Measurements (Reconc

Fair-Value Measurements (Reconciliation of Changes in Derivatives Classified as Level 3) (Details) - Fair Value, Inputs, Level 3 [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	$ 0
Initial valuation of Preferred Distribution Rate Reset Election	(34,450)
Net Loss for the period included in earnings	(10,472)
Allocation of Distribution Paid-in-kind	(287)
Ending Balance	$ (45,209)

Fair-Value Measurements (Narrat

Fair-Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Senior unsecured notes	$ 2,598,918	$ 1,813,169
Fair value of debt	$ 2,700,000	$ 1,900,000

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details)	Sep. 01, 2017
Alkali Business [Member] | Alkali Pension Plan [Member]
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) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Change in benefit obligation:
Benefit Obligation, beginning of year	$ 0
Service Cost	1,749
Interest Cost	267
Actuarial Loss	992
Benefits Paid	(56)
Acquisition of Alkali Business	19,578
Benefit Obligation, end of year	22,530
Change in plan assets:
Fair Value of Plan Assets, beginning of year	0
Actual Return on Plan Assets	647
Employer Contributions	2,250
Benefits Paid	(56)
Acquisition of Alkali Business	10,465
Fair Value of Plan assets, end of year	13,306
Funded Status at end of period	(9,224)
Amounts recognized in the Statement of Financial Position
Non-current assets	0
Current liabilities	0
Non-current Liabilities	(9,224)
Net Asset (Liability) at end of year	(9,224)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss	604
Amounts recognized in accumulated other comprehensive loss:	$ 604

Employee Benefit Plans (Expecte

Employee Benefit Plans (Expected Contributions and Future Benefit Payments) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Employer Contributions
Expected 2018 Contributions by Employer	$ 3,898
Future Expected Benefit Payments
2,018	413
2,019	676
2,020	869
2,021	983
2,022	1,099
2023-2027	$ 7,672

Employee Benefit Plans (Compone

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

Employee Benefit Plans (Fair Va

Employee Benefit Plans (Fair Value Assumptions) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Weighted average assumptions used to determine benefit obligation:
Discount Rate	3.90%	4.15%
Expected Long-term Rate of Return	6.28%

Employee Benefit Plans (Asset T

Employee Benefit Plans (Asset Target Allocation) (Details)	Dec. 31, 2017
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Actual %	41.00%
Equity securities | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	41.00%
Equity securities | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	60.00%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Actual %	50.00%
Fixed income securities | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	40.00%
Fixed income securities | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	50.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Actual %	9.00%
Other | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	0.00%
Other | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Target %	10.00%

Employee Benefit Plans (Fair115

Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 13,306	$ 0
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	260
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	2,518
Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	10,528
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	13,306
Fair Value, Inputs, Level 1 [Member] | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	260
Fair Value, Inputs, Level 1 [Member] | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	2,518
Fair Value, Inputs, Level 1 [Member] | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	10,528
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 2 [Member] | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 2 [Member] | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 2 [Member] | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 3 [Member] | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 3 [Member] | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	0
Fair Value, Inputs, Level 3 [Member] | Mutual and other exchange traded funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of pension plan assets	$ 0

Commitments and Contingencie116

Commitments and Contingencies (Future Minimum Rental Payments Under All Non-Cancelable Operating Leases) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Property Subject to or Available for Operating Lease [Line Items]
2,018	$ 44,580
2,019	41,753
2,020	36,220
2,021	27,596
2,022	23,764
2023 and thereafter	115,937
Total minimum lease obligations	289,850
Office Space
Property Subject to or Available for Operating Lease [Line Items]
2,018	3,972
2,019	3,951
2,020	3,984
2,021	3,233
2,022	2,693
2023 and thereafter	4,696
Total minimum lease obligations	22,529
Transportation equipment
Property Subject to or Available for Operating Lease [Line Items]
2,018	25,871
2,019	25,209
2,020	23,403
2,021	17,818
2,022	16,317
2023 and thereafter	55,614
Total minimum lease obligations	164,232
Terminals and Tanks
Property Subject to or Available for Operating Lease [Line Items]
2,018	14,737
2,019	12,593
2,020	8,833
2,021	6,545
2,022	4,754
2023 and thereafter	55,627
Total minimum lease obligations	$ 103,089

Commitments and Contingencie117

Commitments and Contingencies (Total Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating lease expense	$ 36,933	$ 41,906	$ 36,833

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Remeasurement of deferred taxes due to enacted tax rate change	$ (5,270)	$ 0	$ 0
Current:
Federal	0	0	0
State	100	1,200	1,200
Total current income tax expense (benefit)	100	1,200	1,200
Deferred:
Federal	(5,530)	1,862	2,478
State	1,471	280	309
Total deferred income tax expense (benefit)	(4,059)	2,142	2,787
Income tax expense (benefit)	$ (3,959)	$ 3,342	$ 3,987

Income Taxes (Deferred Tax Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Net operating loss carryforwards	$ 9,506	$ 10,787
Total long-term deferred tax asset	9,506	10,787
Valuation allowances	(1,285)	(869)
Total deferred tax assets	8,221	9,918
Deferred tax liabilities:
Fixed assets	(3,896)	(4,480)
Intangible assets	(15,797)	(20,693)
Other	(441)	(716)
Total long-term liability	(20,134)	(25,889)
Total deferred tax liabilities	(20,134)	(25,889)
Total net deferred tax liability	$ (11,913)	$ (15,971)

Income Taxes (Federal Statutory

Income Taxes (Federal Statutory Income Tax Rate to Income Before Income Taxes) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income from operations before income taxes	$ 78,120,000	$ 114,424,000	$ 425,572,000
Partnership income not subject to federal income tax	(77,704,000)	(109,111,000)	(418,500,000)
Income subject to federal income taxes	416,000	5,313,000	7,072,000
Tax expense at federal statutory rate	146,000	1,860,000	2,475,000
State income taxes, net of federal tax	1,396,000	949,000	928,000
Return to provision, federal and state	(163,000)	(198,000)	(193,000)
Other	(68,000)	731,000	777,000
Remeasurement of deferred taxes due to enacted tax rate change	(5,270,000)	0	0
Income tax expense (benefit)	$ (3,959,000)	$ 3,342,000	$ 3,987,000
Effective tax rate on income from operations before income taxes	(5.00%)	3.00%	1.00%
Liability for uncertain tax positions	$ 0	$ 0	$ 0

Quarterly Financial Data (Un121

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016
Quarterly Financial Data [Abstract]
Revenues from continuing operations	$ 720,049		$ 486,114		$ 406,723		$ 415,491		$ 428,053		$ 460,050		$ 445,976		$ 378,414		$ 2,028,377		$ 1,712,493		$ 2,246,529
Operating income	63,407		43,100		61,447		52,597		43,412		55,179		47,988		59,848		220,551		206,427		156,867
Net income (loss)	15,401		6,160		33,580		26,938		20,321		31,983		23,601		35,177		82,079		111,082		421,585
Net loss attributable to noncontrolling interests	111		152		153		152		1,797		118		126		126		568		2,167		943
Net income attributable to Genesis Energy, L.P.	$ 15,512		$ 6,312		$ 33,733		$ 27,090		$ 22,118		$ 32,101		$ 23,727		$ 35,303		$ 82,647		$ 113,249		$ 422,528
Basic and diluted net income per common unit:
Net income per common unit (in dollars per share)	$ (0.01)		$ 0.01		$ 0.28		$ 0.23		$ 0.19		$ 0.28		$ 0.22		$ 0.32
Cash distributions per common unit (in dollars per share)	$ 0.5000	[1]	$ 0.7225	[1]	$ 0.7200	[1]	$ 0.7100	[1]	$ 0.7000	[1]	$ 0.6900	[1]	$ 0.6725	[1]	$ 0.6550	[1]	$ 0.5000	[1]	$ 0.7000	[1]		$ 0.5000	$ 0.7225	$ 0.7200	$ 0.7100	$ 0.7000	$ 0.6900	$ 0.6725	$ 0.6550
[1]	(1)Represents cash distributions declared and paid in the applicable period.

Condensed Consolidating Fina122

Condensed Consolidating Financial Information (Narrative) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2017USD ($)
Condensed Financial Statements, Captions [Line Items]
Guaranty obligation	$ 2.6
Genesis NEJD Pipeline, LLC [Member]
Condensed Financial Statements, Captions [Line Items]
Percentage of equity interest	100.00%

Condensed Consolidating Fina123

Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 9,041		$ 7,029	$ 10,895	$ 9,462
Other current assets	626,992		352,540
Total current assets	636,033		359,569
Fixed assets, at cost	5,601,015		4,763,396
Less: Accumulated depreciation	(734,986)		(548,532)
Net fixed assets	4,866,029		4,214,864
MINERALS LEASEHOLDS, net of accumulated depletion	564,506		0
Goodwill	325,046		325,046
Other assets, net	364,317		394,357
Advances to affiliates	0		0
Equity investees and other investments	381,550		408,756
Investments in subsidiaries	0		0
TOTAL ASSETS	7,137,481		5,702,592	5,459,599
Current liabilities	456,264		260,803
Senior secured credit facilities	1,099,200		1,278,200
Senior unsecured notes	2,598,918		1,813,169
Deferred tax liabilities	11,913		15,971
Deferred tax liabilities	20,134		25,889
Advances from affiliates	0		0
Other liabilities	256,571		204,481
Total liabilities	4,422,866		3,582,542
Class A Convertible Preferred Units	697,151		0
Partners’ capital, common units	2,026,147		2,130,331
Accumulated other comprehensive loss	(604)	[1]	0
Noncontrolling interests	(8,079)		(10,281)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	7,137,481		5,702,592
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0		0	0	0
Other current assets	0		0
Total current assets	0		0
Fixed assets, at cost	0		0
Less: Accumulated depreciation	0		0
Net fixed assets	0		0
MINERALS LEASEHOLDS, net of accumulated depletion	0		0
Goodwill	0		0
Other assets, net	0		0
Advances to affiliates	0		0
Equity investees and other investments	0		0
Investments in subsidiaries	0		0
TOTAL ASSETS	0		0
Current liabilities	0		0
Senior secured credit facilities	0		0
Senior unsecured notes	0		0
Deferred tax liabilities	0
Deferred tax liabilities			0
Advances from affiliates	0		0
Other liabilities	0		0
Total liabilities	0		0
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	0		0
Accumulated other comprehensive loss	0	[1]	0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	0		0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	6		6	6	9
Other current assets	50		50
Total current assets	56		56
Fixed assets, at cost	0		0
Less: Accumulated depreciation	0		0
Net fixed assets	0		0
MINERALS LEASEHOLDS, net of accumulated depletion	0		0
Goodwill	0		0
Other assets, net	14,083		10,696
Advances to affiliates	3,808,712		2,650,930
Equity investees and other investments	0		0
Investments in subsidiaries	2,689,861		2,594,882
TOTAL ASSETS	6,512,712		5,256,564
Current liabilities	46,086		34,864
Senior secured credit facilities	1,099,200		1,278,200
Senior unsecured notes	2,598,918		1,813,169
Deferred tax liabilities	0
Deferred tax liabilities			0
Advances from affiliates	0		0
Other liabilities	45,210		0
Total liabilities	3,789,414		3,126,233
Class A Convertible Preferred Units	697,151		0
Partners’ capital, common units	2,026,147		2,130,331
Accumulated other comprehensive loss	0	[1]	0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	6,512,712		5,256,564
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	8,340		6,360	8,288	8,310
Other current assets	614,682		340,555
Total current assets	623,022		346,915
Fixed assets, at cost	5,523,431		4,685,811
Less: Accumulated depreciation	(708,269)		(524,315)
Net fixed assets	4,815,162		4,161,496
MINERALS LEASEHOLDS, net of accumulated depletion	564,506		0
Goodwill	325,046		325,046
Other assets, net	378,371		390,214
Advances to affiliates	0		0
Equity investees and other investments	381,550		408,756
Investments in subsidiaries	82,616		80,735
TOTAL ASSETS	7,170,273		5,713,162
Current liabilities	399,017		211,591
Senior secured credit facilities	0		0
Senior unsecured notes	0		0
Deferred tax liabilities	11,913
Deferred tax liabilities			25,889
Advances from affiliates	3,894,027		2,724,224
Other liabilities	182,414		165,266
Total liabilities	4,487,371		3,126,970
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	2,683,506		2,586,192
Accumulated other comprehensive loss	(604)	[1]	0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	7,170,273		5,713,162
Reportable Legal Entities | Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	695		663	2,601	1,143
Other current assets	12,316		12,237
Total current assets	13,011		12,900
Fixed assets, at cost	77,584		77,585
Less: Accumulated depreciation	(26,717)		(24,217)
Net fixed assets	50,867		53,368
MINERALS LEASEHOLDS, net of accumulated depletion	0		0
Goodwill	0		0
Other assets, net	126,300		133,980
Advances to affiliates	85,423		73,295
Equity investees and other investments	0		0
Investments in subsidiaries	0		0
TOTAL ASSETS	275,601		273,543
Current liabilities	11,417		14,505
Senior secured credit facilities	0		0
Senior unsecured notes	0		0
Deferred tax liabilities	0
Deferred tax liabilities			0
Advances from affiliates	0		0
Other liabilities	183,237		179,592
Total liabilities	194,654		194,097
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	89,026		89,727
Accumulated other comprehensive loss	0	[1]	0
Noncontrolling interests	(8,079)		(10,281)
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	275,601		273,543
Eliminations
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0		0	$ 0	$ 0
Other current assets	(56)		(302)
Total current assets	(56)		(302)
Fixed assets, at cost	0		0
Less: Accumulated depreciation	0		0
Net fixed assets	0		0
MINERALS LEASEHOLDS, net of accumulated depletion	0		0
Goodwill	0		0
Other assets, net	(154,437)		(140,533)
Advances to affiliates	(3,894,135)		(2,724,225)
Equity investees and other investments	0		0
Investments in subsidiaries	(2,772,477)		(2,675,617)
TOTAL ASSETS	(6,821,105)		(5,540,677)
Current liabilities	(256)		(157)
Senior secured credit facilities	0		0
Senior unsecured notes	0		0
Deferred tax liabilities	0
Deferred tax liabilities			0
Advances from affiliates	(3,894,027)		(2,724,224)
Other liabilities	(154,290)		(140,377)
Total liabilities	(4,048,573)		(2,864,758)
Class A Convertible Preferred Units	0		0
Partners’ capital, common units	(2,772,532)		(2,675,919)
Accumulated other comprehensive loss	0	[1]	0
Noncontrolling interests	0		0
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$ (6,821,105)		$ (5,540,677)
[1]	The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our Guarantor Subsidiaries.

Condensed Consolidating Fina124

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									$ 318,239	$ 334,679	$ 140,230
Sodium minerals and sulfur services									462,622	171,503	177,880
Marine transportation									205,287	213,021	238,757
Onshore facilities and transportation									1,042,229	993,290	1,689,662
Total revenues	$ 720,049	$ 486,114	$ 406,723	$ 415,491	$ 428,053	$ 460,050	$ 445,976	$ 378,414	2,028,377	1,712,493	2,246,529
Onshore facilities and transportation costs									968,647	924,627	1,602,808
Marine transportation operating costs									154,606	142,551	135,200
Sodium minerals and sulfur services operating costs									333,918	91,443	96,806
Offshore pipeline transportation operating costs									72,065	79,624	39,713
General and administrative									66,421	45,625	64,995
Depreciation, depletion and amortization									252,480	222,196	150,140
Gain on sale of assets									(40,311)	0	0
Total costs and expenses									1,807,826	1,506,066	2,089,662
OPERATING INCOME	63,407	43,100	61,447	52,597	43,412	55,179	47,988	59,848	220,551	206,427	156,867
Equity in earnings of equity investees									51,046	47,944	54,450
Equity in earnings of subsidiaries									0	0	0
Gain on basis step up on historical interest									0	0	332,380
Interest expense									(176,762)	(139,947)	(100,596)
Other expense, net									(16,715)	0	(17,529)
Income from operations before income taxes									78,120	114,424	425,572
Income tax benefit (expense)									3,959	(3,342)	(3,987)
NET INCOME	15,401	6,160	33,580	26,938	20,321	31,983	23,601	35,177	82,079	111,082	421,585
Net loss attributable to noncontrolling interests	111	152	153	152	1,797	118	126	126	568	2,167	943
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$ 15,512	$ 6,312	$ 33,733	$ 27,090	$ 22,118	$ 32,101	$ 23,727	$ 35,303	82,647	113,249	422,528
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(21,995)	0	0
Net Income Available to Common Unitholders									60,652	113,249	422,528
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									0	0	0
Sodium minerals and sulfur services									0	0	0
Marine transportation									0	0	0
Onshore facilities and transportation									0	0	0
Total revenues									0	0	0
Onshore facilities and transportation costs									0	0	0
Marine transportation operating costs									0	0	0
Sodium minerals and sulfur services operating costs									0	0	0
Offshore pipeline transportation operating costs									0	0	0
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets									0
Total costs and expenses									0	0	0
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									0	0	0
Gain on basis step up on historical interest											0
Interest expense									0	0	0
Other expense, net									0	0	0
Income from operations before income taxes									0	0	0
Income tax benefit (expense)									0	0	0
NET INCOME									0	0	0
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.									0	0	0
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income Available to Common Unitholders									0	0	0
Reportable Legal Entities | Genesis Energy, L.P. (Parent and Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									0	0	0
Sodium minerals and sulfur services									0	0	0
Marine transportation									0	0	0
Onshore facilities and transportation									0	0	0
Total revenues									0	0	0
Onshore facilities and transportation costs									0	0	0
Marine transportation operating costs									0	0	0
Sodium minerals and sulfur services operating costs									0	0	0
Offshore pipeline transportation operating costs									0	0	0
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets									0
Total costs and expenses									0	0	0
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									276,341	253,048	542,226
Gain on basis step up on historical interest											0
Interest expense									(176,979)	(139,799)	(100,494)
Other expense, net									(16,715)	0	(19,204)
Income from operations before income taxes									82,647	113,249	422,528
Income tax benefit (expense)									0	0	0
NET INCOME									82,647	113,249	422,528
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.									82,647	113,249	422,528
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									(21,995)	0	0
Net Income Available to Common Unitholders									60,652	113,249	422,528
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									318,239	334,679	137,681
Sodium minerals and sulfur services									460,790	171,389	175,132
Marine transportation									205,287	213,021	238,757
Onshore facilities and transportation									1,023,293	972,794	1,665,917
Total revenues									2,007,609	1,691,883	2,217,487
Onshore facilities and transportation costs									967,558	923,567	1,601,972
Marine transportation operating costs									154,606	142,551	135,200
Sodium minerals and sulfur services operating costs									332,209	90,711	94,241
Offshore pipeline transportation operating costs									69,225	68,791	38,459
General and administrative									66,421	45,625	64,995
Depreciation, depletion and amortization									249,980	219,696	141,785
Gain on sale of assets									(40,311)
Total costs and expenses									1,799,688	1,490,941	2,076,652
OPERATING INCOME									207,921	200,942	140,835
Equity in earnings of equity investees									51,046	47,944	54,450
Equity in earnings of subsidiaries									(520)	(6,744)	2,053
Gain on basis step up on historical interest											332,380
Interest expense									14,122	14,407	15,042
Other expense, net									0	0	1,675
Income from operations before income taxes									272,569	256,549	546,435
Income tax benefit (expense)									3,928	(3,337)	(4,036)
NET INCOME									276,497	253,212	542,399
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.									276,497	253,212	542,399
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income Available to Common Unitholders									276,497	253,212	542,399
Reportable Legal Entities | Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									0		2,549
Sodium minerals and sulfur services									9,252	7,873	11,942
Marine transportation									0	0	0
Onshore facilities and transportation									18,936	20,496	23,745
Total revenues									28,188	28,369	38,236
Onshore facilities and transportation costs									1,089	1,060	836
Marine transportation operating costs									0	0	0
Sodium minerals and sulfur services operating costs									9,129	8,491	11,759
Offshore pipeline transportation operating costs									2,840	10,833	1,254
General and administrative									0	0	0
Depreciation, depletion and amortization									2,500	2,500	8,355
Gain on sale of assets									0
Total costs and expenses									15,558	22,884	22,204
OPERATING INCOME									12,630	5,485	16,032
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									0	0	0
Gain on basis step up on historical interest											0
Interest expense									(13,905)	(14,555)	(15,144)
Other expense, net									0	0	0
Income from operations before income taxes									(1,275)	(9,070)	888
Income tax benefit (expense)									31	(5)	49
NET INCOME									(1,244)	(9,075)	937
Net loss attributable to noncontrolling interests									568	2,167	943
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.									(676)	(6,908)	1,880
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income Available to Common Unitholders									(676)	(6,908)	1,880
Eliminations
Condensed Financial Statements, Captions [Line Items]
Offshore pipeline transportation services									0	0	0
Sodium minerals and sulfur services									(7,420)	(7,759)	(9,194)
Marine transportation									0	0	0
Onshore facilities and transportation									0	0	0
Total revenues									(7,420)	(7,759)	(9,194)
Onshore facilities and transportation costs									0	0	0
Marine transportation operating costs									0	0	0
Sodium minerals and sulfur services operating costs									(7,420)	(7,759)	(9,194)
Offshore pipeline transportation operating costs									0	0	0
General and administrative									0	0	0
Depreciation, depletion and amortization									0	0	0
Gain on sale of assets									0
Total costs and expenses									(7,420)	(7,759)	(9,194)
OPERATING INCOME									0	0	0
Equity in earnings of equity investees									0	0	0
Equity in earnings of subsidiaries									(275,821)	(246,304)	(544,279)
Gain on basis step up on historical interest											0
Interest expense									0	0	0
Other expense, net									0	0	0
Income from operations before income taxes									(275,821)	(246,304)	(544,279)
Income tax benefit (expense)									0	0	0
NET INCOME									(275,821)	(246,304)	(544,279)
Net loss attributable to noncontrolling interests									0	0	0
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.									(275,821)	(246,304)	(544,279)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units									0	0	0
Net Income Available to Common Unitholders									$ (275,821)	$ (246,304)	$ (544,279)

Condensed Consolidating Fina125

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 338,858	$ 298,338	$ 289,536
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(250,593)	(463,100)	(495,774)
Cash distributions received from equity investees - return of investment	20,280	21,353	25,645
Investments in equity investees	(4,647)	0	(3,045)
Acquisitions	(1,325,759)	(25,394)	(1,520,299)
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	124	13,374	3,179
Proceeds from asset sales	85,722	3,609	2,811
Other, net	0	(151)	(1,976)
Net cash used in investing activities	(1,474,873)	(450,309)	(1,989,459)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,458,700	1,115,800	1,525,050
Repayments on senior secured credit facility	(1,637,700)	(952,600)	(960,450)
Proceeds from issuance of senior unsecured notes	1,000,000	0	1,139,718
Proceeds from issuance of Class A convertible preferred units, net	726,419	0	0
Repayment of senior unsecured notes	(204,830)	0	(350,000)
Debt issuance costs	(25,913)	(1,578)	(28,901)
Intercompany transfers	0	0	0
Issuance of common units for cash, net	140,513	298,020	633,759
Distributions to partners/owners	(321,875)	(310,039)	(256,389)
Contributions (distributions) from (to) noncontrolling interests	2,770	236	(960)
Other, net	(57)	(1,734)	(471)
Net cash provided by financing activities	1,138,027	148,105	1,701,356
Net decrease in cash and cash equivalents	2,012	(3,866)	1,433
Cash and cash equivalents at beginning of period	7,029	10,895	9,462
Cash and cash equivalents at end of period	9,041	7,029	10,895
Reportable Legal Entities | Genesis Energy Finance Corporation (Co-Issuer)
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	0	0	0
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees - return of investment	0	0	0
Investments in equity investees	0	0	0
Acquisitions	0	0	0
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	0	0	0
Proceeds from asset sales	0	0	0
Other, net	0	0	0
Net cash used in investing activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes	0		0
Proceeds from issuance of Class A convertible preferred units, net	0
Repayment of senior unsecured notes	0		0
Debt issuance costs	0	0	0
Intercompany transfers	0	0	0
Issuance of common units for cash, net	0	0	0
Distributions to partners/owners	0	0	0
Contributions (distributions) from (to) noncontrolling interests	0	0	0
Other, net	0	0	0
Net cash provided by financing activities	0	0	0
Net decrease in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(301,264)	(289,421)	(49,651)
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees - return of investment	0	0	(186,026)
Investments in equity investees	140,513	298,020	633,761
Acquisitions	0	0	0
Intercompany transfers	1,157,781	31,436	1,240,973
Repayments on loan to non-guarantor subsidiary	(6,764)	(6,113)	(5,524)
Contributions in aid of construction costs	0	0	0
Proceeds from asset sales	0	0	0
Other, net	0	0	0
Net cash used in investing activities	1,291,530	323,343	1,683,184
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes	0		0
Proceeds from issuance of Class A convertible preferred units, net	0
Repayment of senior unsecured notes	0		0
Debt issuance costs	0	0	0
Intercompany transfers	(1,157,781)	(31,437)	(1,240,973)
Issuance of common units for cash, net	(140,513)	(298,020)	(633,759)
Distributions to partners/owners	321,875	310,039	256,389
Contributions (distributions) from (to) noncontrolling interests	0	0	0
Other, net	(13,847)	(14,504)	(15,190)
Net cash provided by financing activities	(990,266)	(33,922)	(1,633,533)
Net decrease in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Genesis Energy, L.P. (Parent and Co-Issuer) | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	162,980	179,853	(14,082)
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees - return of investment	0	0	186,026
Investments in equity investees	(140,513)	(298,020)	(633,761)
Acquisitions	0	0	0
Intercompany transfers	(1,157,781)	(31,436)	(1,240,973)
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	0	0	0
Proceeds from asset sales	0	0	0
Other, net	0	0	0
Net cash used in investing activities	(1,298,294)	(329,456)	(1,688,708)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,458,700	1,115,800	1,525,050
Repayments on senior secured credit facility	(1,637,700)	(952,600)	(960,450)
Proceeds from issuance of senior unsecured notes	1,000,000		1,139,718
Proceeds from issuance of Class A convertible preferred units, net	726,419
Repayment of senior unsecured notes	(204,830)		(350,000)
Debt issuance costs	(25,913)	(1,578)	(28,901)
Intercompany transfers	0	0	0
Issuance of common units for cash, net	140,513	298,020	633,759
Distributions to partners/owners	(321,875)	(310,039)	(256,389)
Contributions (distributions) from (to) noncontrolling interests	0	0	0
Other, net	0	0	0
Net cash provided by financing activities	1,135,314	149,603	1,702,787
Net decrease in cash and cash equivalents	0	0	(3)
Cash and cash equivalents at beginning of period	6	6	9
Cash and cash equivalents at end of period	6	6	6
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	481,727	398,320	308,144
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	(250,593)	(463,100)	(495,774)
Cash distributions received from equity investees - return of investment	20,280	21,353	25,645
Investments in equity investees	(4,647)	0	(3,045)
Acquisitions	(1,325,759)	(25,394)	(1,520,299)
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	6,764	6,113	5,524
Contributions in aid of construction costs	124	13,374	3,179
Proceeds from asset sales	85,722	3,609	2,811
Other, net	0	(151)	(1,976)
Net cash used in investing activities	(1,468,109)	(444,196)	(1,983,935)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes	0		0
Proceeds from issuance of Class A convertible preferred units, net	0
Repayment of senior unsecured notes	0		0
Debt issuance costs	0	0	0
Intercompany transfers	1,169,781	57,701	1,299,830
Issuance of common units for cash, net	140,513	298,020	633,759
Distributions to partners/owners	(321,875)	(310,039)	(256,389)
Contributions (distributions) from (to) noncontrolling interests	0	0	(960)
Other, net	(57)	(1,734)	(471)
Net cash provided by financing activities	988,362	43,948	1,675,769
Net decrease in cash and cash equivalents	1,980	(1,928)	(22)
Cash and cash equivalents at beginning of period	6,360	8,288	8,310
Cash and cash equivalents at end of period	8,340	6,360	8,288
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(4,585)	9,586	45,125
CASH FLOWS FROM OPERATING ACTIVITIES:
Payments to acquire fixed and intangible assets	0	0	0
Cash distributions received from equity investees - return of investment	0	0	0
Investments in equity investees	0	0	0
Acquisitions	0	0	0
Intercompany transfers	0	0	0
Repayments on loan to non-guarantor subsidiary	0	0	0
Contributions in aid of construction costs	0	0	0
Proceeds from asset sales	0	0	0
Other, net	0	0	0
Net cash used in investing activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	0	0	0
Repayments on senior secured credit facility	0	0	0
Proceeds from issuance of senior unsecured notes	0		0
Proceeds from issuance of Class A convertible preferred units, net	0
Repayment of senior unsecured notes	0		0
Debt issuance costs	0	0	0
Intercompany transfers	(12,000)	(26,264)	(58,857)
Issuance of common units for cash, net	0	0	0
Distributions to partners/owners	0	0	0
Contributions (distributions) from (to) noncontrolling interests	2,770	236	0
Other, net	13,847	14,504	15,190
Net cash provided by financing activities	4,617	(11,524)	(43,667)
Net decrease in cash and cash equivalents	32	(1,938)	1,458
Cash and cash equivalents at beginning of period	663	2,601	1,143
Cash and cash equivalents at end of period	$ 695	$ 663	$ 2,601

Subsequent Events (Details)

Subsequent Events (Details) - 5.750% senior unsecured notes - USD ($) $ in Thousands	Feb. 15, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 08, 2013
Subsequent Event [Line Items]
Debt issued, aggregate principal amount		$ 145,170	$ 350,000	$ 350,000
Debt instrument, stated rate				5.75%
Subsequent Event [Member]
Subsequent Event [Line Items]
Debt called for redemption	$ 145,200
Debt percentage of principal amount redeemed	101.438%