UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2020~~March 31, 2021

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

Delaware

76-0513049

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification No.)

919 Milam, Suite 2100,

Houston

77002

(Address of principal executive offices)

(Zip code)

Registrant’s telephone number, including area code:

(713)

860-2500


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common units	GEL	NYSE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

☐

Emerging growth company

☐

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding as of ~~November~~May 5, ~~2020.~~2021.

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GENESIS ENERGY, L.P.

TABLE OF CONTENTS


		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Comprehensive Income	5
	Unaudited Condensed Consolidated Statements of Partners’ Capital	6
	Unaudited Condensed Consolidated Statements of Cash Flows	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
	1. Organization and Basis of Presentation and Consolidation	8
	2. Recent Accounting Developments	9
	3. Revenue Recognition	109
	4. Lease Accounting	1110
	5. Inventories	1311
	6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations	1412
	7. Equity Investees	1513
	8. Intangible Assets	1614
	9. Debt	1715
	10. Partners' Capital, Mezzanine Capital and Distributions	1816
	11. Net Income (Loss) Per Common Unit	2119
	12. Business Segment Information	2220
	13. Transactions with Related Parties	2522
	14. Supplemental Cash Flow Information	2623
	15. Derivatives	2623
	16. Fair-Value Measurements	2926
	17. Commitments and Contingencies	3128
	18. Subsequent Events	3128

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3229
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5550
Item 4.	Controls and Procedures	5550
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	5651
Item 1A.	Risk Factors	5651
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5651
Item 3.	Defaults upon Senior Securities	5651
Item 4.	Mine Safety Disclosures	5651
Item 5.	Other Information	5651
Item 6.	Exhibits	5752
SIGNATURES		5853

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS
CURRENT ASSETS:	CURRENT ASSETS:					CURRENT ASSETS:
Cash and cash equivalents	Cash and cash equivalents	$	36,504	$	29,128	Cash and cash equivalents	$	18,449	$	21,282
Restricted cash	Restricted cash	7,512		27,277		Restricted cash	15,338		5,736
Accounts receivable - trade, net	Accounts receivable - trade, net	247,819		417,002		Accounts receivable - trade, net	473,929		392,465
Inventories	Inventories	89,811		65,137		Inventories	72,427		99,877
Net investment in direct financing leases, net of unearned income		69,370		9,293

Other	Other	65,576		45,237		Other	64,000		60,809
Total current assets	Total current assets	516,592		593,074		Total current assets	644,143		580,169
FIXED ASSETS, at cost	FIXED ASSETS, at cost	5,209,403		5,540,596		FIXED ASSETS, at cost	5,206,508		5,173,475
Less: Accumulated depreciation	Less: Accumulated depreciation	(1,295,654)		(1,246,121)		Less: Accumulated depreciation	(1,381,384)		(1,322,141)
Net fixed assets	Net fixed assets	3,913,749		4,294,475		Net fixed assets	3,825,124		3,851,334
MINERAL LEASEHOLDS, net of accumulated depletion	MINERAL LEASEHOLDS, net of accumulated depletion	553,417		555,825		MINERAL LEASEHOLDS, net of accumulated depletion	551,663		552,575
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income		0		107,702

EQUITY INVESTEES	EQUITY INVESTEES	321,541		334,523		EQUITY INVESTEES	310,024		319,068
INTANGIBLE ASSETS, net of amortization	INTANGIBLE ASSETS, net of amortization	129,178		138,927		INTANGIBLE ASSETS, net of amortization	127,848		128,742
GOODWILL	GOODWILL	301,959		301,959		GOODWILL	301,959		301,959
RIGHT OF USE ASSETS, net	RIGHT OF USE ASSETS, net	159,488		177,071		RIGHT OF USE ASSETS, net	149,711		153,925
OTHER ASSETS, net of amortization	OTHER ASSETS, net of amortization	57,426		94,085		OTHER ASSETS, net of amortization	39,141		45,847
TOTAL ASSETS	TOTAL ASSETS	$	5,953,350	$	6,597,641	TOTAL ASSETS	$	5,949,613	$	5,933,619
LIABILITIES AND CAPITAL	LIABILITIES AND CAPITAL					LIABILITIES AND CAPITAL
CURRENT LIABILITIES:	CURRENT LIABILITIES:					CURRENT LIABILITIES:
Accounts payable - trade	Accounts payable - trade	$	151,762	$	218,737	Accounts payable - trade	$	257,728	$	198,433
Accrued liabilities	Accrued liabilities	181,840		196,758		Accrued liabilities	196,366		184,978

Total current liabilities	Total current liabilities	333,602		415,495		Total current liabilities	454,094		383,411
SENIOR SECURED CREDIT FACILITY	SENIOR SECURED CREDIT FACILITY	984,800		959,300		SENIOR SECURED CREDIT FACILITY	699,000		643,700
SENIOR UNSECURED NOTES, net of debt issuance costs	SENIOR UNSECURED NOTES, net of debt issuance costs	2,373,928		2,469,937		SENIOR UNSECURED NOTES, net of debt issuance costs	2,671,262		2,750,016
DEFERRED TAX LIABILITIES	DEFERRED TAX LIABILITIES	12,665		12,640		DEFERRED TAX LIABILITIES	13,389		13,317
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES	378,870		393,850		OTHER LONG-TERM LIABILITIES	410,189		393,018
Total liabilities	Total liabilities	4,083,865		4,251,222		Total liabilities	4,247,934		4,183,462

MEZZANINE CAPITAL:	MEZZANINE CAPITAL:					MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at September 30, 2020 and December 31, 2019		790,115		790,115
Redeemable noncontrolling interests, 139,359 and 130,000 preferred units issued and outstanding at September 30, 2020 and December 31, 2019, respectively		137,475		125,133
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at March 31, 2021 and December 31, 2020						Class A Convertible Preferred Units, 25,336,778 issued and outstanding at March 31, 2021 and December 31, 2020	790,115		790,115
Redeemable noncontrolling interests, 161,209 and 141,249 preferred units issued and outstanding at March 31, 2021 and December 31, 2020, respectively						Redeemable noncontrolling interests, 161,209 and 141,249 preferred units issued and outstanding at March 31, 2021 and December 31, 2020, respectively	163,655		141,194

PARTNERS’ CAPITAL:	PARTNERS’ CAPITAL:					PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 units issued and outstanding at September 30, 2020 and December 31, 2019		951,554		1,443,320
Common unitholders, 122,579,218 units issued and outstanding at March 31, 2021 and December 31, 2020						Common unitholders, 122,579,218 units issued and outstanding at March 31, 2021 and December 31, 2020	758,031		829,326
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(8,066)		(8,431)		Accumulated other comprehensive loss	(9,243)		(9,365)
Noncontrolling interests	Noncontrolling interests	(1,593)		(3,718)		Noncontrolling interests	(879)		(1,113)
Total partners' capital	Total partners' capital	941,895		1,431,171		Total partners' capital	747,909		818,848
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	5,953,350	$	6,597,641	TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	5,949,613	$	5,933,619

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
REVENUES:	REVENUES:									REVENUES:
Offshore pipeline transportation	Offshore pipeline transportation	$	53,893	$	79,738	$	197,286	$	236,482	Offshore pipeline transportation		$	64,384	$	78,429
Sodium minerals and sulfur services	Sodium minerals and sulfur services	206,731		277,527		642,745		827,619		Sodium minerals and sulfur services		227,287		243,390
Marine transportation	Marine transportation	51,912		59,404		170,978		174,760		Marine transportation		40,331		62,346
Onshore facilities and transportation	Onshore facilities and transportation	130,589		205,028		360,506		637,630		Onshore facilities and transportation		189,217		155,758
Total revenues	Total revenues	443,125		621,697		1,371,515		1,876,491		Total revenues		521,219		539,923
COSTS AND EXPENSES:	COSTS AND EXPENSES:									COSTS AND EXPENSES:
Onshore facilities and transportation product costs	Onshore facilities and transportation product costs	103,245		160,772		258,644		495,927		Onshore facilities and transportation product costs		160,751		111,952
Onshore facilities and transportation operating costs	Onshore facilities and transportation operating costs	16,984		19,550		53,470		58,377		Onshore facilities and transportation operating costs		16,262		18,248
Marine transportation operating costs	Marine transportation operating costs	36,342		44,831		117,840		133,400		Marine transportation operating costs		33,086		42,937
Sodium minerals and sulfur services operating costs	Sodium minerals and sulfur services operating costs	178,688		222,304		550,931		660,906		Sodium minerals and sulfur services operating costs		184,431		205,233
Offshore pipeline transportation operating costs	Offshore pipeline transportation operating costs	21,698		22,932		56,762		45,507		Offshore pipeline transportation operating costs		20,716		18,661
General and administrative	General and administrative	11,072		14,999		45,858		40,097		General and administrative		11,666		9,373
Depreciation, depletion and amortization	Depreciation, depletion and amortization	67,733		83,522		222,210		240,513		Depreciation, depletion and amortization		66,286		74,357
Impairment expense		3,331		0		280,826		0

Total costs and expenses	Total costs and expenses	439,093		568,910		1,586,541		1,674,727		Total costs and expenses		493,198		480,761
OPERATING INCOME (LOSS)		4,032		52,787		(215,026)		201,764
OPERATING INCOME										OPERATING INCOME		28,021		59,162
Equity in earnings of equity investees	Equity in earnings of equity investees	14,439		11,830		41,216		39,873		Equity in earnings of equity investees		20,660		14,159
Interest expense	Interest expense	(51,312)		(54,673)		(157,895)		(165,881)		Interest expense		(57,829)		(54,965)
Other income, net		7,406		7,974		13,114		306
Income (loss) before income taxes		(25,435)		17,918		(318,591)		76,062
Income tax expense		(145)		(111)		(575)		(656)
Other income (expense)										Other income (expense)		(20,065)		10,258
Income (loss) from operations before income taxes										Income (loss) from operations before income taxes		(29,213)		28,614
Income tax (expense) benefit										Income tax (expense) benefit		(222)		365

NET INCOME (LOSS)	NET INCOME (LOSS)	(25,580)		17,807		(319,166)		75,406		NET INCOME (LOSS)		(29,435)		28,979
Net loss (income) attributable to noncontrolling interests		12		22		38		(1,503)
Net loss attributable to noncontrolling interests										Net loss attributable to noncontrolling interests		2		16
Net income attributable to redeemable noncontrolling interests	Net income attributable to redeemable noncontrolling interests	(4,149)		(272)		(12,394)		(272)		Net income attributable to redeemable noncontrolling interests		(4,791)		(4,086)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	(29,717)	$	17,557	$	(331,522)	$	73,631	NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.		$	(34,224)	$	24,909
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(18,684)		(18,684)		(56,052)		(55,783)		Less: Accumulated distributions attributable to Class A Convertible Preferred Units		(18,684)		(18,684)
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS	NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS	$	(48,401)	$	(1,127)	$	(387,574)	$	17,848	NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS		$	(52,908)	$	6,225
NET INCOME (LOSS) PER COMMON UNIT (Note 11):	NET INCOME (LOSS) PER COMMON UNIT (Note 11):									NET INCOME (LOSS) PER COMMON UNIT (Note 11):

Basic and Diluted	Basic and Diluted	$	(0.39)	$	(0.01)	$	(3.16)	$	0.15	Basic and Diluted		$	(0.43)	$	0.05
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:	WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:									WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	Basic and Diluted	122,579		122,579		122,579		122,579		Basic and Diluted		122,579		122,579

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Net income (loss)	Net income (loss)	$	(25,580)	$	17,807	$	(319,166)	$	75,406	Net income (loss)		$	(29,435)	$	28,979
Other comprehensive income:	Other comprehensive income:									Other comprehensive income:
Amortization of prior service cost	Amortization of prior service cost	122		0		365		0		Amortization of prior service cost		122		0
Total Comprehensive income (loss)	Total Comprehensive income (loss)	(25,458)		17,807		(318,801)		75,406		Total Comprehensive income (loss)		(29,313)		28,979
Comprehensive loss (income) attributable to noncontrolling interests		12		22		38		(1,503)
Comprehensive loss attributable to noncontrolling interests										Comprehensive loss attributable to noncontrolling interests		2		16
Comprehensive income attributable to redeemable noncontrolling interests	Comprehensive income attributable to redeemable noncontrolling interests	(4,149)		(272)		(12,394)		(272)		Comprehensive income attributable to redeemable noncontrolling interests		(4,791)		(4,086)
Comprehensive income (loss) attributable to Genesis Energy, L.P.	Comprehensive income (loss) attributable to Genesis Energy, L.P.	$	(29,595)	$	17,557	$	(331,157)	$	73,631	Comprehensive income (loss) attributable to Genesis Energy, L.P.		$	(34,102)	$	24,909

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

Number of Common Units Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, June 30, 2020 122,579 $ 1,018,342 $ (1,900) $ (8,188) $ 1,008,254
Net loss — (29,717) (12) — (29,729)
Cash distributions to partners — (18,387) — — (18,387)
Cash contributions from noncontrolling interests — — 319 — 319
Other comprehensive income — — — 122 122
Distributions to Class A Convertible Preferred unitholders — (18,684) — — (18,684)
Partners' capital, September 30, 2020 122,579 $ 951,554 $ (1,593) $ (8,066) $ 941,895
Number of Common Units Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Income Total
Partners’ capital, June 30, 2019 122,579 $ 1,575,599 $ (8,449) $ 939 $ 1,568,089
Net income — 17,557 (22) — 17,535
Cash distributions to partners — (67,418) — — (67,418)
Cash contributions from noncontrolling interests — — 2,375 — 2,375
Distributions to Class A Convertible Preferred unitholders — (18,684) — — (18,684)
Partners' capital, September 30, 2019 122,579 $ 1,507,054 $ (6,096) $ 939 $ 1,501,897


		Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total			Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total
Partners’ capital, January 1, 2020		122,579	$	1,443,320	$	(3,718)	$	(8,431)	$	1,431,171
Partners’ capital, January 1, 2021											Partners’ capital, January 1, 2021	122,579	$	829,326	$	(1,113)	$	(9,365)	$	818,848

Net loss	Net loss	—	(331,522)		(38)		—		(331,560)		Net loss	—	(34,224)		(2)		—		(34,226)

Cash distributions to partners	Cash distributions to partners	—	(104,192)		—		—		(104,192)		Cash distributions to partners	—	(18,387)		—		—		(18,387)
Cash contributions from noncontrolling interests	Cash contributions from noncontrolling interests	—	—		2,163		—		2,163		Cash contributions from noncontrolling interests	—	—		236		—		236

Other comprehensive income	Other comprehensive income	—	—		—		365		365		Other comprehensive income	—	—		—		122		122
Distributions to Class A Convertible Preferred unitholders	Distributions to Class A Convertible Preferred unitholders	—	(56,052)		—		—		(56,052)		Distributions to Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)

Partners' capital, September 30, 2020		122,579	$	951,554	$	(1,593)	$	(8,066)	$	941,895
Partners' capital, March 31, 2021											Partners' capital, March 31, 2021	122,579	$	758,031	$	(879)	$	(9,243)	$	747,909
		Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Income		Total			Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total
Partners’ capital, January 1, 2019		122,579	$	1,690,799	$	(11,204)	$	939	$	1,680,534
Partners’ capital, January 1, 2020											Partners’ capital, January 1, 2020	122,579	$	1,443,320	$	(3,718)	$	(8,431)	$	1,431,171
Net income	Net income	—	73,631		1,503		—		75,134		Net income	—	24,909		(16)		—		24,893

Cash distributions to partners	Cash distributions to partners	—	(202,256)		—		—		(202,256)		Cash distributions to partners	—	(67,419)		—		—		(67,419)
Cash contributions from noncontrolling interests	Cash contributions from noncontrolling interests	—	—		3,605		—		3,605		Cash contributions from noncontrolling interests	—	—		1,377		—		1,377

Distributions to Class A Convertible Preferred unitholders	Distributions to Class A Convertible Preferred unitholders	—	(55,120)		—		—		(55,120)		Distributions to Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)

Partners' capital, September 30, 2019		122,579	$	1,507,054	$	(6,096)	$	939	$	1,501,897
Partners' capital, March 31, 2020											Partners' capital, March 31, 2020	122,579	$	1,382,126	$	(2,357)	$	(8,431)	$	1,371,338

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES:	CASH FLOWS FROM OPERATING ACTIVITIES:					CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	Net income (loss)	$	(319,166)	$	75,406	Net income (loss)	$	(29,435)	$	28,979
Adjustments to reconcile net income (loss) to net cash provided by operating activities -	Adjustments to reconcile net income (loss) to net cash provided by operating activities -					Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Depreciation, depletion and amortization	Depreciation, depletion and amortization	222,210		240,513		Depreciation, depletion and amortization	66,286		74,357

Impairment expense		280,826		0

Amortization and write-off of debt issuance costs and discount	Amortization and write-off of debt issuance costs and discount	17,515		8,065		Amortization and write-off of debt issuance costs and discount	3,210		11,527
Amortization of unearned income and initial direct costs on direct financing leases		(8,217)		(9,271)
Payments received under direct financing leases		56,837		15,501
Amortization of non-cash costs on previously owned direct financing leases						Amortization of non-cash costs on previously owned direct financing leases	—		(2,929)
Payments received under previously owned direct financing leases (Note 4)						Payments received under previously owned direct financing leases (Note 4)	17,500		5,167
Equity in earnings of investments in equity investees	Equity in earnings of investments in equity investees	(41,216)		(39,873)		Equity in earnings of investments in equity investees	(20,660)		(14,159)
Cash distributions of earnings of equity investees	Cash distributions of earnings of equity investees	40,773		39,725		Cash distributions of earnings of equity investees	19,929		13,505
Non-cash effect of long-term incentive compensation plans	Non-cash effect of long-term incentive compensation plans	(2,806)		6,298		Non-cash effect of long-term incentive compensation plans	1,560		(5,027)
Deferred and other tax liabilities		25		296
Deferred and other tax liabilities (benefits)						Deferred and other tax liabilities (benefits)	72		(515)
Unrealized (gains) losses on derivative transactions	Unrealized (gains) losses on derivative transactions	(19,582)		4,231		Unrealized (gains) losses on derivative transactions	17,599		(31,118)
Cancellation of debt income		(20,534)		0

Other, net	Other, net	16,817		(3,518)		Other, net	6,160		2,231
Net changes in components of operating assets and liabilities (Note 14)	Net changes in components of operating assets and liabilities (Note 14)	72,146		(5,644)		Net changes in components of operating assets and liabilities (Note 14)	(5,062)		7,534
Net cash provided by operating activities	Net cash provided by operating activities	295,628		331,729		Net cash provided by operating activities	77,159		89,552
CASH FLOWS FROM INVESTING ACTIVITIES:	CASH FLOWS FROM INVESTING ACTIVITIES:					CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	Payments to acquire fixed and intangible assets	(100,381)		(109,598)		Payments to acquire fixed and intangible assets	(39,388)		(38,001)
Cash distributions received from equity investees - return of investment	Cash distributions received from equity investees - return of investment	14,943		18,333		Cash distributions received from equity investees - return of investment	9,314		7,060

Proceeds from asset sales	Proceeds from asset sales	447		890		Proceeds from asset sales	23		61

Net cash used in investing activities	Net cash used in investing activities	(84,991)		(90,375)		Net cash used in investing activities	(30,051)		(30,880)
CASH FLOWS FROM FINANCING ACTIVITIES:	CASH FLOWS FROM FINANCING ACTIVITIES:					CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	Borrowings on senior secured credit facility	814,100		597,500		Borrowings on senior secured credit facility	212,000		393,500
Repayments on senior secured credit facility	Repayments on senior secured credit facility	(788,600)		(620,600)		Repayments on senior secured credit facility	(156,700)		(375,400)
Proceeds from issuance of senior unsecured notes due 2028	Proceeds from issuance of senior unsecured notes due 2028	750,000		0		Proceeds from issuance of senior unsecured notes due 2028	0		750,000
Net proceeds from issuance of preferred units (Note 10)	Net proceeds from issuance of preferred units (Note 10)	0		49,400		Net proceeds from issuance of preferred units (Note 10)	17,738		0
Repayment of senior unsecured notes	Repayment of senior unsecured notes	(827,031)		0		Repayment of senior unsecured notes	(80,859)		(750,000)
Debt issuance costs	Debt issuance costs	(15,279)		0		Debt issuance costs	(1,916)		(13,295)

Contributions from noncontrolling interests	Contributions from noncontrolling interests	2,163		3,605		Contributions from noncontrolling interests	236		1,377
Distributions to common unitholders	Distributions to common unitholders	(104,192)		(202,256)		Distributions to common unitholders	(18,387)		(67,419)
Distributions to preferred unitholders	Distributions to preferred unitholders	(56,052)		(24,822)		Distributions to preferred unitholders	(18,684)		(18,684)
Other, net	Other, net	1,865		2,128		Other, net	6,233		6,353
Net cash used in financing activities	Net cash used in financing activities	(223,026)		(195,045)		Net cash used in financing activities	(40,339)		(73,568)
Net increase (decrease) decrease in cash, restricted cash, and cash equivalents		(12,389)		46,309
Net increase (decrease) in cash, restricted cash, and cash equivalents						Net increase (decrease) in cash, restricted cash, and cash equivalents	6,769		(14,896)
Cash, restricted cash and cash equivalents at beginning of period	Cash, restricted cash and cash equivalents at beginning of period	56,405		10,300		Cash, restricted cash and cash equivalents at beginning of period	27,018		56,405
Cash, restricted cash and cash equivalents at end of period	Cash, restricted cash and cash equivalents at end of period	$	44,016	$	56,609	Cash, restricted cash and cash equivalents at end of period	$	33,787	$	41,509

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry as well as the production of natural soda ash. Our operations are located primarily in the Gulf Coast region of the United States, Wyoming, and the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our ~~soda ash~~trona and trona-based exploring, mining, processing, producing, marketing, and selling business based in Wyoming (our "Alkali Business"), refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.

We currently manage our businesses through the following 4 divisions that constitute our reportable segments:

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

•Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as the 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 the terminalling, blending, storing, marketing and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and CO2other heavy refined products); and

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

Basis of Presentation and Consolidation

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

Our results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The Unaudited Condensed Consolidated Financial Statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC"). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles ("GAAP") have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the Consolidated Financial Statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (our "Annual Report").

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.

Covid-19 and Market Update

In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and Infrastructure Security Agency ("CISA") and we have continued to operate our assets during this pandemic.

Covid-19 has caused commodity prices to decline due to, among other things, reduced industrial activity and travel demand that are expected to continue in the near future. Beginning in the second quarter of 2020, our results were negatively impacted, primarily through lower volumes and demand for our assets, by the macroeconomic conditions and current operating environment. Additionally, as a result of lower current demand and the outlook for our crude-by-rail logistics assets, and rail becoming an uneconomic means of transportation for producers to get crude oil to their refineries, we recognized a non-cash impairment charge associated with these assets in our onshore facilities and transportation segment during the second quarter of 2020 (refer to ~~Note 6~~ ~~for additional discussion). In response to the pandemic and as part of our overall cost savings strategy,~~

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~~during the second quarter of 2020 we recorded a one-time charge of approximately $13 million associated with restructuring and severance expenses incurred during the period.~~

In addition to Covid-19, which continued to negatively impact our results due to the lower demand and volumes across our businesses during the third quarter of 2020, we experienced several hurricanes, including Hurricane Laura, which caused downtime and damage to certain of our assets in the Gulf of Mexico causing a one-time increase in operating costs of approximately $5 million in our offshore pipeline transportation segment. As we exited the third quarter of 2020, we began to see a slight recovery in volumes and demand as certain regions of the United States and the world begin to re-open their economies. We considered the impact of lower commodity prices and Covid-19 on the assumptions and estimates reflected in our financial statements.

We believe we are still well positioned and have adequate liquidity, especially when considering our recurring and estimated nonrecurring cash obligations, to operate through the rest of the pandemic and continue our natural path of deleveraging our balance sheet. See further ~~discussion on Covid-19~~discussed in Item 2. Management's Discussion and Analysis of Financial Condition and Results of ~~Operations.~~Operations, the impact of the Covid-19 pandemic and the related economic, business and market disruptions continues to evolve and its future effects, including the severity and duration, remain uncertain.

We continue to monitor the market environment and will evaluate whether any triggering events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions

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deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our results of operations.

2. Recent Accounting Developments

Recently Adopted

We have adopted guidance under ASC Topic 326, Financial Instruments - Credit Losses ("ASC 326"), as of January 1, 2020. The standard changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We have assessed our receivables for expected losses by considering current and historical information pertaining to our trade accounts and existing contract assets. Our assessment resulted in an immaterial impact to our consolidated financial statements as of the adoption date and for the three and nine months ended September 30, 2020.

During the first quarter of 2020, the SEC amended the financial disclosure requirements for guarantors and issuers of guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X to go in effect January 4, 2021. The amendment simplifies the disclosure requirements and permits the amended disclosures to be provided outside the footnotes in audited annual or unaudited interim consolidated financial statements in all filings. As permitted by the amendment, we have early adopted the amendment and included the required summarized financial information in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

3. Revenue Recognition

Revenue from Contracts with Customers

The following tables reflect the disaggregation of our revenues by major category for the 2021 Quarter and the three months ended ~~September 30,~~March 31, 2020 ~~and 2019,~~(the "2020 Quarter"), respectively:


		Three Months Ended September 30, 2020											Three Months Ended March 31, 2021
		Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated			Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	Fee-based revenues	$	53,893	$	0	$	51,912	$	22,406	$	128,211	Fee-based revenues	$	64,384	$	0	$	40,331	$	24,394	$	129,109
Product Sales	Product Sales	0		188,201		0		108,183		296,384		Product Sales	0		204,778		0		164,823		369,601
Refinery Services	Refinery Services	0		18,530		0		0		18,530		Refinery Services	0		22,509		0		0		22,509
		$	53,893	$	206,731	$	51,912	$	130,589	$	443,125		$	64,384	$	227,287	$	40,331	$	189,217	$	521,219

Three Months Ended
September 30, 2019
Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated
Fee-based revenues $ 79,738 $ 0 $ 59,404 $ 36,937 $ 176,079
Product Sales 0 259,332 0 168,091 427,423
Refinery Services 0 18,195 0 0 18,195
$ 79,738 $ 277,527 $ 59,404 $ 205,028 $ 621,697

~~The following tables reflect the disaggregation of our revenues by major category for the nine months ended September 30, 2020 and 2019, respectively:~~

Nine Months Ended
September 30, 2020
Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated
Fee-based revenues $ 197,286 $ 0 $ 170,978 $ 85,241 $ 453,505
Product Sales 0 575,977 0 275,265 851,242
Refinery Services 0 66,768 0 0 66,768
$ 197,286 $ 642,745 $ 170,978 $ 360,506 $ 1,371,515


		Nine Months Ended September 30, 2019											Three Months Ended March 31, 2020
		Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated			Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated
Fee-based revenues	Fee-based revenues	$	236,482	$	0	$	174,760	$	112,713	$	523,955	Fee-based revenues	$	78,429	$	0	$	62,346	$	40,990	$	181,765
Product Sales	Product Sales	0		769,264		0		524,917		1,294,181		Product Sales	0		215,366		0		114,768		330,134
Refinery Services	Refinery Services	0		58,355		0		0		58,355		Refinery Services	0		28,024		0		0		28,024
		$	236,482	$	827,619	$	174,760	$	637,630	$	1,876,491		$	78,429	$	243,390	$	62,346	$	155,758	$	539,923

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

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Contract Assets and Liabilities

The table below depicts our contract asset and liability balances at December 31, ~~2019~~2020 and ~~September 30, 2020:~~March 31, 2021:

Contract Assets Contract Liabilities
Current Non-Current Current Non-Current
Balance at December 31, 2019 $ 21,912 $ 54,232 $ 2,896 $ 23,170
Balance at September 30, 2020 36,558 20,209 3,020 20,929


	Contract Assets				Contract Liabilities
	Current		Non-Current		Current		Non-Current
Balance at December 31, 2020	$	36,500	$	12,065	$	2,988	$	19,834
Balance at March 31, 2021	35,930		3,174		2,849		19,187

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Transaction Price Allocations to Remaining Performance Obligations

We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance obligations as of ~~September 30, 2020.~~March 31, 2021. We are exempted from disclosing performance obligations with a duration of one year or less, revenue recognized related to performance obligations where the consideration corresponds directly with the value provided to customers, and contracts with variable consideration that is allocated wholly to an unsatisfied performance obligation or promise to transfer a good or service that is part of a series in accordance with ASC 606.

The majority of our contracts qualify for one of these expedients or exemptions. For the remaining contract types that involve revenue recognition over a long-term period with long-term fixed consideration (adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance obligations. For our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long term period. Therefore, we have allocated the remaining contract value to future periods.

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


		Offshore Pipeline Transportation		Onshore Facilities and Transportation			Offshore Pipeline Transportation		Onshore Facilities and Transportation
Remainder of 2020		$	17,015	$	15,868
2021		62,937		22,271
Remainder of 2021						Remainder of 2021	$	48,198	$	14,369
2022	2022	73,204		4,703		2022	75,623		4,703
2023	2023	61,503		0		2023	63,982		0
2024	2024	53,778		0		2024	56,326		0
2025						2025	60,311		0
Thereafter	Thereafter	156,136		0		Thereafter	97,761		0
Total	Total	$	424,573	$	42,842	Total	$	402,201	$	19,072

4. Lease Accounting

Lessee Arrangements

We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of less than 12 months are not recorded on our Unaudited Condensed Consolidated Balance Sheets. Lease expenses are recognized on a straight line basis over the lease term.

Our Right of Use Assets, net balance includes our unamortized initial direct costs associated with certain of our transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease. Our lease liability includes our remaining provision for ~~each period presented for~~ our cease-use provision for railcars no longer in use. Our short-term and long-term lease liabilities are recorded within "Accrued liabilities" and "Other long-term liabilities," respectively, on our Unaudited Condensed Consolidated Balance Sheets.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Lessor Arrangements

We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties.

Operating Leases

During the ~~three~~2021 Quarter and ~~nine months ended September 30,~~ 2020 Quarter, we acted as a lessor in revenue contracts associated with the M/T American Phoenix, which is included in our marine transportation segment. During the 2020 Quarter, we acted as a lessor in our ~~revenue contract associated with our~~ Free State pipeline system, which is included in our onshore facilities and transportation ~~segment, and the M/T American Phoenix, included in our marine transportation~~ segment. These revenues are recorded within ~~its~~their respective segment's revenues in the Unaudited Condensed Consolidated Statements of Operations. Our lease revenues for these arrangements (inclusive of fixed and variable consideration) are reflected in the table ~~below for the three and nine months ended September 30, 2020 and 2019, respectively:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
M/T American Phoenix $ 6,787 $ 6,808 $ 20,164 $ 20,202
Free State Pipeline 1,467 1,290 4,889 4,174

~~The following table details the fixed future lease payments we will receive for our lessor arrangements classified as operating leases as of September 30, 2020:~~

Maturity of Lessor Receipts Onshore Facilities and Transportation
Remainder of 2020 $ 300
2021 1,200
2022 1,200
2023 1,200
2024 1,200
Thereafter 4,100
Total Lease Receipts $ 9,200

~~Direct Finance Lease~~

Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008. These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028, we will convey all of our interest in the NEJD pipeline to the lessee for a nominal payment. During the third quarter of 2020, our customer defaulted under the agreement and we exercised a letter of credit we had issued to us as beneficiary and collected approximately $41 million in cash. As of September 30, 2020, the present value of our lease receivables for our direct finance lease is $69.4 million, which is inclusive of our unamortized initial direct costs, and is presented as current on the Unaudited Condensed Consolidated Balance Sheet in accordance with the default terms under the arrangement.

below:

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended March 31,
		2021		2020
M/T American Phoenix		$	3,420	$	6,643
Free State Pipeline (1)		0		1,923

(1) We sold the Free State pipeline to a subsidiary of Denbury, Inc. ("Denbury") on October 30, 2020.

Direct Finance Lease

We formerly held a direct finance lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the finance lease, we were paid a quarterly payment, which commenced in August 3, 2008. During the third quarter of 2020, our customer, Denbury, defaulted under the agreement. On October 30, 2020 we executed an agreement with our customer to accelerate the remaining principal payments on the previously owned NEJD direct financing lease, payable in 4 equal installments. During the period ending March 31, 2021, we collected $17.5 million and we have an outstanding receivable (included within "Accounts receivable- trade, net" on the Unaudited Condensed Consolidated Balance Sheets) of $52.5 million as of March 31, 2021 from Denbury for the remaining payments due in 2021 per the agreement. Additionally as part of this transaction, we transferred the ownership of all of our CO2 assets to Denbury, including the Free State pipeline system as noted previously.

5. Inventories

The major components of inventories were as follows:


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Petroleum products	Petroleum products	$	1,868	$	2,721	Petroleum products	$	2,584	$	5,840
Crude oil	Crude oil	29,012		5,271		Crude oil	14,633		37,661
Caustic soda	Caustic soda	5,510		5,965		Caustic soda	5,108		5,167
NaHS	NaHS	10,056		10,845		NaHS	7,736		9,101
Raw materials - Alkali operations	Raw materials - Alkali operations	7,194		6,238		Raw materials - Alkali operations	6,492		7,120
Work-in-process - Alkali operations	Work-in-process - Alkali operations	8,565		8,579		Work-in-process - Alkali operations	10,700		9,355
Finished goods, net - Alkali operations	Finished goods, net - Alkali operations	15,086		14,168		Finished goods, net - Alkali operations	11,988		13,002
Materials and supplies, net - Alkali operations	Materials and supplies, net - Alkali operations	12,520		11,350		Materials and supplies, net - Alkali operations	13,186		12,631

Total	Total	$	89,811	$	65,137	Total	$	72,427	$	99,877

Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories ~~was adjusted $4.1 million~~were recorded below cost by $0.4 million and $5.0 million as of ~~September 30, 2020, with 0 such adjustment as of~~March 31, 2021 and December 31, ~~2019.~~2020, respectively, therefore we reduced the value of our inventory in our Unaudited Consolidated Financial Statements by these amounts.

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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations

Fixed Assets

Fixed assets, net consisted of the following:


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Crude oil pipelines and natural gas pipelines and related assets	Crude oil pipelines and natural gas pipelines and related assets	$	2,880,802	$	2,891,489	Crude oil pipelines and natural gas pipelines and related assets	$	2,810,931	$	2,811,030
Alkali facilities, machinery, and equipment	Alkali facilities, machinery, and equipment	614,403		591,547		Alkali facilities, machinery, and equipment	635,446		622,598
Onshore facilities, machinery, and equipment	Onshore facilities, machinery, and equipment	264,763		640,376		Onshore facilities, machinery, and equipment	268,571		267,810
Transportation equipment	Transportation equipment	19,336		19,864		Transportation equipment	19,520		19,470
Marine vessels	Marine vessels	993,346		979,171		Marine vessels	1,002,601		998,553
Land, buildings and improvements	Land, buildings and improvements	217,770		238,451		Land, buildings and improvements	220,454		219,382
Office equipment, furniture and fixtures	Office equipment, furniture and fixtures	21,993		22,645		Office equipment, furniture and fixtures	22,096		22,001
Construction in progress	Construction in progress	155,099		115,162		Construction in progress	183,628		170,740
Other	Other	41,891		41,891		Other	43,261		41,891
Fixed assets, at cost	Fixed assets, at cost	5,209,403		5,540,596		Fixed assets, at cost	5,206,508		5,173,475
Less: Accumulated depreciation	Less: Accumulated depreciation	(1,295,654)		(1,246,121)		Less: Accumulated depreciation	(1,381,384)		(1,322,141)
Net fixed assets	Net fixed assets	$	3,913,749	$	4,294,475	Net fixed assets	$	3,825,124	$	3,851,334

Mineral Leaseholds

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


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Mineral leaseholds	Mineral leaseholds	$	566,019	$	566,019	Mineral leaseholds	$	566,019	$	566,019
Less: Accumulated depletion	Less: Accumulated depletion	(12,602)		(10,194)		Less: Accumulated depletion	(14,356)		(13,444)
Mineral leaseholds, net of accumulated depletion	Mineral leaseholds, net of accumulated depletion	$	553,417	$	555,825	Mineral leaseholds, net of accumulated depletion	$	551,663	$	552,575

Our depreciation and depletion expense for the periods presented was as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
Depreciation expense $ 62,499 $ 77,228 $ 206,830 $ 222,106
Depletion expense 604 1,204 2,408 3,488

~~Impairment Expense~~

During the second quarter of 2020, due to the challenging economic environment from the decline in commodity prices (including the collapse in the differential of Western Canadian Select to the Gulf Coast) and Covid-19, crude-by-rail transportation became uneconomic for producers and the current demand and outlook for our rail logistics assets declined. Due to this, we identified a triggering event that required us to perform an impairment test.

For our recoverability test, we utilized management's estimates, including current contractual commitments, for our future cash inflows, and our costs and expenses were determined based on the estimated fixed and variable requirements to operate and maintain the related assets. As our rail logistics asset groups did not pass the initial recoverability assessment, we subsequently performed a fair value calculation using a discounted cash flow model under the income approach. As a result of this test, we recognized impairment expense of approximately $277 million associated with the rail logistics assets in our onshore facilities and transportation segment, as the carrying value of our assets exceeded the estimated realizable value, including approximately $272 million of net fixed assets and approximately $5 million of right of use assets, net on the Unaudited Condensed Consolidated Balance Sheet. The fair value estimates used in the long-lived asset test were primarily based on level 3 inputs of the fair value hierarchy.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

In addition to this, we recognized impairment expense of $3.3 million during the third quarter of 2020 primarily associated with the full write-down of a non-core gas platform in our offshore transportation segment due to it not having a future use for our operations.


	Three Months Ended March 31,
		2021		2020
Depreciation expense		$	62,702	$	69,242
Depletion expense		912		963

Asset Retirement Obligations

We record asset retirement obligations ("AROs") in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations.

The following table presents information regarding our AROs since December 31, ~~2019:~~2020:


ARO liability balance, December 31, ~~2019~~2020	$	~~175,081~~176,852
Accretion expense	~~6,809~~2,584
Changes in estimate	~~609~~797


Settlements	~~(11,547)~~(2,017)

ARO liability balance, ~~September 30, 2020~~March 31, 2021	$	~~170,952~~178,216

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the ARO balances disclosed above, ~~$11.2~~$13.6 million and ~~$26.6~~$14.7 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively. The remainder of the ARO liability as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 is included in "Other long-term liabilities" on our Unaudited Condensed Consolidated Balance ~~Sheet.~~Sheets.

With respect to our AROs, the following table presents our estimate of accretion expense for the periods indicated:

Remainder of 2020 $ 2,619
2021 $ 9,493
2022 $ 9,513
2023 $ 10,183
2024 $ 10,900


Remainder of	2021	$	7,532
	2022	$	9,384
	2023	$	9,128
	2024	$	9,783
	2025	$	10,487

Certain of our unconsolidated affiliates have AROs recorded at ~~September 30, 2020~~March 31, 2021 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Unaudited Condensed Consolidated Financial Statements.

7. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. 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. Such excess cost amounts are included within the carrying values of our equity investees. At ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, the unamortized excess cost amounts totaled ~~$339.2~~$331.5 million and ~~$350.9~~$335.4 million, respectively. We amortize the excess cost as a reduction in equity earnings.

The following table presents information included in our Unaudited Condensed Consolidated Financial Statements related to our equity ~~investees.~~investees:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Genesis’ share of operating earnings	Genesis’ share of operating earnings	$	18,312	$	15,703	$	52,834	$	51,491	Genesis’ share of operating earnings		$	24,533	$	18,032
Amortization of excess purchase price	Amortization of excess purchase price	(3,873)		(3,873)		(11,618)		(11,618)		Amortization of excess purchase price		(3,873)		(3,873)
Net equity in earnings	Net equity in earnings	$	14,439	$	11,830	$	41,216	$	39,873	Net equity in earnings		$	20,660	$	14,159
Distributions received	Distributions received	$	16,757	$	19,512	$	55,716	$	58,058	Distributions received		$	29,516	$	20,565

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

The following tables present the unaudited balance sheet and income statement information (on a 100% basis) for Poseidon Oil Pipeline Company, L.L.C. ("Poseidon") (which is our most significant equity investment):


		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
BALANCE SHEET DATA:	BALANCE SHEET DATA:					BALANCE SHEET DATA:
Assets	Assets					Assets
Current assets	Current assets	$	30,868	$	30,307	Current assets	$	17,531	$	30,465
Fixed assets, net	Fixed assets, net	175,628		187,091		Fixed assets, net	168,723		171,732
Other assets	Other assets	1,833		2,113		Other assets	5,036		4,673
Total assets	Total assets	$	208,329	$	219,511	Total assets	$	191,290	$	206,870
Liabilities and equity	Liabilities and equity					Liabilities and equity
Current liabilities	Current liabilities	$	11,047	$	15,558	Current liabilities	$	11,720	$	9,958
Other liabilities	Other liabilities	240,527		245,976		Other liabilities	229,008		237,595
Equity	Equity	(43,245)		(42,023)		Equity	(49,438)		(40,683)
Total liabilities and equity	Total liabilities and equity	$	208,329	$	219,511	Total liabilities and equity	$	191,290	$	206,870

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
INCOME STATEMENT DATA:
Revenues $ 35,351 $ 30,602 $ 98,662 $ 96,041
Operating income $ 27,002 $ 21,745 $ 72,530 $ 69,705
Net income $ 25,831 $ 19,431 $ 68,050 $ 62,576

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended March 31,
		2021		2020
INCOME STATEMENT DATA:
Revenues		$	42,413	$	32,892
Operating income		$	32,161	$	23,606
Net income		$	31,145	$	21,583

Poseidon's Revolving Credit Facility

Borrowings under Poseidon’s revolving credit facility, which was amended and restated in March 2019, are primarily used to fund spending on capital projects. The March 2019 credit facility is non-recourse to Poseidon’s owners and secured by substantially all of Poseidon's assets and has a maturity date of March 2024. The March 2019 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 Unaudited Condensed Consolidated Financial Statements.

8. Intangible Assets

The following table summarizes the components of our intangible assets at the dates indicated:

September 30, 2020 December 31, 2019
Gross
Carrying
Amount Accumulated
Amortization Carrying
Value Gross
Carrying
Amount Accumulated
Amortization Carrying
Value
Marine contract intangibles(1)
$ 800 $ 561 $ 239 $ 27,800 $ 23,033 $ 4,767
Offshore pipeline contract intangibles 158,101 42,992 115,109 158,101 36,752 121,349
Other 27,009 13,179 13,830 34,291 21,480 12,811
Total $ 185,910 $ 56,732 $ 129,178 $ 220,192 $ 81,265 $ 138,927

~~(1) The contract intangible associated with the M/T American Phoenix became fully amortized and retired as of September 30, 2020.~~


	March 31, 2021						December 31, 2020
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Marine contract intangibles	$	800	$	580	$	220	$	800	$	571	$	229
Offshore pipeline contract intangibles	158,101		47,153		110,948		158,101		45,073		113,028
Other	30,949		14,269		16,680		29,244		13,759		15,485
Total	$	189,850	$	62,002	$	127,848	$	188,145	$	59,403	$	128,742

Our amortization of intangible assets for the periods presented was as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
Amortization of intangible assets $ 4,555 $ 4,928 $ 12,817 $ 14,029


	Three Months Ended March 31,
		2021		2020
Amortization of intangible assets		$	2,600	$	4,116

We estimate that our amortization expense for the next five years will be as follows:


Remainder of	2021	$	8,323
	2022	$	10,973
	2023	$	10,705
	2024	$	10,390
	2025	$	10,222

1614

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~We estimate that our amortization expense for the next five years will be as follows:~~

Remainder of 2020 $ 2,781
2021 $ 10,729
2022 $ 10,571
2023 $ 10,303
2024 $ 9,988

9. Debt

Our obligations under debt arrangements consisted of the following:


		September 30, 2020						December 31, 2019							March 31, 2021						December 31, 2020
		Principal		Unamortized Debt Issuance Costs (1)		Net Value		Principal		Unamortized Discount and Debt Issuance Costs (1)		Net Value			Principal		Unamortized Debt Issuance Costs (1)		Net Value		Principal		Unamortized Discount and Debt Issuance Costs (1)		Net Value
Senior secured credit facility	Senior secured credit facility	$	984,800	$	0	$	984,800	$	959,300	$	0	$	959,300	Senior secured credit facility	$	699,000	$	0	$	699,000	$	643,700	$	0	$	643,700
6.750% senior unsecured notes due 2022		0		0		0		750,000		9,349		740,651
6.000% senior unsecured notes due 2023	6.000% senior unsecured notes due 2023	398,905		2,749		396,156		400,000		3,557		396,443		6.000% senior unsecured notes due 2023	0		0		0		80,859		504		80,355
5.625% senior unsecured notes due 2024	5.625% senior unsecured notes due 2024	341,135		3,177		337,958		350,000		3,923		346,077		5.625% senior unsecured notes due 2024	341,135		2,749		338,386		341,135		2,963		338,172
6.500% senior unsecured notes due 2025	6.500% senior unsecured notes due 2025	534,834		5,936		528,898		550,000		7,020		542,980		6.500% senior unsecured notes due 2025	534,834		5,343		529,491		534,834		5,639		529,195
6.250% senior unsecured notes due 2026	6.250% senior unsecured notes due 2026	400,712		4,883		395,829		450,000		6,214		443,786		6.250% senior unsecured notes due 2026	359,799		3,994		355,805		359,799		4,189		355,610
8.000% senior unsecured notes due 2027														8.000% senior unsecured notes due 2027	750,000		12,524		737,476		750,000		13,022		736,978
7.750% senior unsecured notes due 2028	7.750% senior unsecured notes due 2028	726,849		11,762		715,087		0		0		0		7.750% senior unsecured notes due 2028	720,975		10,871		710,104		720,975		11,269		709,706
Total long-term debt	Total long-term debt	$	3,387,235	$	28,507	$	3,358,728	$	3,459,300	$	30,063	$	3,429,237	Total long-term debt	$	3,405,743	$	35,481	$	3,370,262	$	3,431,302	$	37,586	$	3,393,716

(1) Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Unaudited Condensed Consolidated Balance ~~Sheet)~~Sheets) were ~~$6.9~~$4.8 million and ~~$7.6~~$5.8 million as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively.

As of ~~September 30, 2020,~~March 31, 2021, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Senior Secured Credit Facility

~~The~~At March 31, 2021, 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 1.75% to 3.50% on Eurodollar borrowings and from 0.75% to 2.50% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At ~~September 30, 2020,~~March 31, 2021, the applicable margins on our borrowings were ~~2.00%~~2.50% for alternate base rate borrowings and ~~3.00%~~3.50% for Eurodollar rate borrowings.

•Letter of credit fee rates range from 1.75% to 3.50% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At ~~September 30, 2020,~~March 31, 2021, our letter of credit rate was ~~3.00%~~3.50%.

•We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee rates on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio. At ~~September 30, 2020,~~March 31, 2021, our commitment fee rate on the unused committed amount was 0.50%.

•The accordion feature is $300.0 million, giving us the ability to expand the size of the facility to up to $2.0 billion for acquisitions or growth projects, subject to lender consent.

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

On March 25, 2020, we amended our credit agreement. This amendment, among other things, (i) sets the maximum Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) at 3.25 to 1.00 throughout the remaining term of the facility, and (ii) allows us to purchase certain of our outstanding senior unsecured notes, subject to certain customary conditions.

~~On July 24, 2020, we further amended our credit agreement. This amendment increases our Consolidated Leverage Ratio from 5.50X to 5.75X from September 30, 2020 through~~At March 31, 2021, after which time it reverts back to 5.50X for the remaining term of the agreement. Additionally, it decreases our Consolidated Interest Coverage Ratio from 3.0X to 2.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 3.0X for the remaining term of the agreement.

~~At September 30, 2020,~~ we had ~~$984.8~~$699.0 million borrowed under our $1.7 billion credit facility, with ~~$27.8~~$13.0 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to ~~$100.0~~$200.0 million of the capacity to be used for letters of credit, of which ~~$1.1~~$1.3 million was outstanding at ~~September 30, 2020.~~March 31, 2021. 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. The total amount available for borrowings under our existing credit facility at ~~September 30, 2020~~March 31, 2021 was ~~$714.1~~$999.7 million, subject to compliance with covenants.

On April 8, 2021, we entered into an amended and restated credit facility agreement to, among other things, extend the term of our existing credit facility. Refer to Note 18 for additional details.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries (as defined below in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations), and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Genesis Alkali Holdings Company, LLC ("Alkali Holdings") and Genesis Energy, L.P., to the extent agreed to in the services agreement between Genesis Energy, L.P. and Alkali Holdings dated as of September 23, 2019 (the "Services Agreement").

Senior Unsecured Note Transactions

On January 16, 2020, we issued ~~$750.0~~$750 million in aggregate principal amount of our 7.75% senior unsecured notes due February 15, 2028 (the “2028 Notes”). Interest payments are due February 1 and August 1 of each ~~year with the initial interest payment due on August 1, 2020.~~year. That issuance generated net proceeds of $736.7 million, net of issuance costs incurred. ~~The~~We used $554.8 million of the net proceeds ~~were used~~ to ~~purchase $527.9 million~~redeem a portion of ~~our existing~~the 6.75% senior unsecured notes due August 1, 2022 (the ~~“2022 Notes”~~"2022 Notes"), including ~~the related~~principal, accrued interest and tender premium ~~on those notes,~~that were validly tendered, and the remaining net proceeds ~~at the time~~ were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the remaining $222.1 million of our 2022 Notes, and they were redeemed on February 16, 2020. We incurred a total loss of approximately $23.5 million relating to the extinguishment of our 2022 senior unsecured notes, inclusive of our transactions costs and the write-off of the related unamortized debt issuance costs and discount, which is recorded in "Other income ~~net"~~(expense)" in our Unaudited Condensed Consolidated Statements of Operations for the ~~nine months ended September 30, 2020.~~2020 Quarter.

~~During~~On December 17, 2020, we ~~repurchased certain~~issued $750 million in aggregate principal amount of our 8.00% senior unsecured notes due January 15, 2027 (the "2027 Notes"). Interest payments are due on January 15 and July 15 of each year with the ~~open market~~initial interest payment due on July 15, 2021. The issuance generated net proceeds of approximately $737 million, net of issuance costs incurred. We used $316.5 million of the net proceeds to repay the portion of the 6.00% senior unsecured notes due May 15, 2023 (the "2023 Notes") (including principal, accrued interest and tender premium) that were validly tendered, and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of $80.9 million in accordance with the terms and conditions of the indenture governing the 2023 Notes. We incurred a total loss of approximately $1.6 million relating to the extinguishment of our remaining 2023 senior unsecured notes, inclusive of the redemption fee and the write-off of the related unamortized debt issuance costs, which is recorded ~~cancellation of debt income of $0.8 million and $20.5 million for the three and nine months ended September 30, 2020, respectively. These are recorded within~~in "Other income ~~net"~~(expense)" in our Unaudited Condensed Consolidated Statements of ~~Operations.~~Operations for the 2021 Quarter.

On April 22, 2021 we completed our offering of an additional $250 million in aggregate principal amount of the 2027 Notes. The notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms as (other than with respect to the issue price) and constitute part of the same series of the 2027 Notes we issued on December 17, 2020. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. Refer to

Note 18 for details around this additional offering.

10. Partners’ Capital, Mezzanine Capital and Distributions

At ~~September 30, 2020,~~March 31, 2021, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units.

Distributions

We paid or will pay the following distributions to our common unitholders in 2020 and 2021:


Distribution For	Date Paid		Per Unit Amount		Total Amount
2020
1st Quarter	May 15, 2020		$	0.15	$	18,387
2nd Quarter	August 14, 2020		$	0.15	$	18,387
3rd Quarter	November 13, 2020		$	0.15	$	18,387
4th Quarter	February 12, 2021		$	0.15	$	18,387
2021
1st Quarter	May 14, 2021	(1)	$	0.15	$	18,387

(1) This distribution was declared on April 7, 2021 and will be paid to unitholders of record as of April 30, 2021.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Distributions~~

~~We paid or will pay the following distributions to our common unitholders in 2019 and 2020:~~

Distribution For Date Paid Per Unit
Amount Total
Amount
2019
1st Quarter
May 15, 2019 $ 0.5500 $ 67,419
2nd Quarter
August 14, 2019 $ 0.5500 $ 67,419
3rd Quarter
November 14, 2019 $ 0.5500 $ 67,419
4th Quarter
February 14, 2020 $ 0.5500 $ 67,419
2020
1st Quarter
May 15, 2020 $ 0.1500 $ 18,387
2nd Quarter
August 14, 2020

$ 0.1500 $ 18,387
3rd Quarter
November 13, 2020 (1) $ 0.1500 $ 18,387

~~(1) This distribution was declared on October 6, 2020 and will be paid to unitholders of record as of October 30, 2020.~~

Class A Convertible Preferred Units

At ~~September 30, 2020~~March 31, 2021 we had 25,336,778 Class A Convertible Preferred Units (our "Class A Convertible Preferred Units") outstanding. Our Class A Convertible Preferred Units rank senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those Class A Convertible Preferred Units.

Accounting for the Class A Convertible Preferred Units

Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event that is outside our control. Therefore, we present them as temporary equity in the mezzanine section of the Unaudited Condensed Consolidated Balance Sheets. Because our Class A Convertible Preferred Units are not currently redeemable and we do not have plans or expect any events that constitute a change of control in our partnership agreement, we present our Class A Convertible Preferred Units at their initial carrying amount. However, we would be required to adjust that carrying amount if it becomes probable that we would be required to redeem our Class A Convertible Preferred Units.

Initial and Subsequent Measurement

We initially recognized our Class A Convertible Preferred Units at their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of our Class A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our Class A Convertible Preferred Units to the redemption value over a period of time comprising the date the feature first becomes probable and the date the units can first be redeemed. Our Class A Convertible Preferred Units contain a distribution Rate Reset Election (as defined in Note 15) ~~option.~~. This Rate Reset Election is bifurcated and accounted for separately as an embedded derivative and recorded at fair value at each reporting period. Refer to Note 15 and Note 16 for additional discussion.

~~Class A Convertible Preferred Unit distributions are recognized on the date in which they are declared. Paid-in-kind ("PIK") distributions were declared and issued as follows:~~

Distribution For Date Issued
Number of Units (1)
Total Amount
2019
1st Quarter
May 15, 2019 364,180 $ 12,277

~~(1) Subsequent to the first quarter of 2019, all distributions have been and will be paid in cash.~~

Net Income (Loss) Attributable to Genesis Energy, L.P. is reduced by Class A Convertible Preferred Unit distributions that accumulated during the period. Net ~~income (loss) attributable~~Income (Loss) Attributable to Genesis Energy, L.P. was reduced by $18.7 million for the 2021 Quarter and 2020 Quarter.

We paid or will pay the following cash distributions to our Class A Convertible Preferred unitholders in 2020 and 2021:


Distribution For	Date Paid		Per Unit Amount		Total Amount
2020
1st Quarter	May 15, 2020		$	0.7374	$	18,684
2nd Quarter	August 14, 2020		$	0.7374	$	18,684
3rd Quarter	November 13, 2020		$	0.7374	$	18,684
4th Quarter	February 12, 2021		$	0.7374	$	18,684
2021
1st Quarter	May 14, 2021	(1)	$	0.7374	$	18,684

(1) This distribution was declared on April 7, 2021 and will be paid to unitholders of record as of April 30, 2021.

1917

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~$56.1 million for the three and nine months ended September 30, 2020, and $18.7 million and $55.8 million for the three and nine months ended September 30, 2019.~~

~~We paid or will pay the following cash distributions to our Class A Convertible Preferred unitholders in 2019 and 2020:~~

Distribution For Date Paid Per Unit
Amount Total
Amount
2019
1st Quarter
May 15, 2019 $ 0.2458 $ 6,138
2nd Quarter
August 14, 2019 $ 0.7374 $ 18,684
3rd Quarter
November 14, 2019 $ 0.7374 $ 18,684
4th Quarter
February 14, 2020 $ 0.7374 $ 18,684
2020
1st Quarter
May 15, 2020 $ 0.7374 $ 18,684
2nd Quarter
August 14, 2020 $ 0.7374 $ 18,684
3rd Quarter
November 13, 2020 (1) $ 0.7374 $ 18,684

~~(1) This distribution was declared on October 6, 2020 and will be paid to unitholders of record as of October 30, 2020.~~

Redeemable Noncontrolling Interests

On September 23, 2019, we, through a subsidiary, Alkali Holdings, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain investment fund entities affiliated with GSO Capital Partners LP (collectively "GSO") purchased $55,000,000 (or 55,000 Alkali Holdings preferred units) and committed to purchase up to $350,000,000 of preferred units in Alkali Holdings, the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the net proceeds from the Alkali Holdings preferred units to fund up to 100% of the anticipated cost of expansion of the Granger facility. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one ~~year.~~year, which we currently anticipate completing near the end of 2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to GSO, which was accounted for as issuance costs. As part of ~~September 30, 2020,~~the amendment, the commitment period was increased to four years, and the total commitment of GSO was increased to, subject to compliance with the covenants contained in the agreements with GSO, up to $351,750,000 preferred units (or 351,750 preferred units) in Alkali Holdings. As of March 31, 2021, there are ~~139,359~~161,209 Alkali Holdings preferred units outstanding.

Accounting for Redeemable Noncontrolling Interests

Classification

The Alkali Holdings preferred units issued and outstanding are accounted for as a redeemable noncontrolling interest in the mezzanine section on our Unaudited Condensed Consolidated Balance Sheets due to the redemption features for a change of control.

Initial and Subsequent Measurement

We recorded the Alkali Holdings preferred units at their issuance date fair value, net of issuance costs. The fair value as of ~~September 30, 2020~~March 31, 2021 represents the carrying amount based on the issued and outstanding Alkali Holdings preferred units most probable redemption event on the six and a half year anniversary of the closing, which is the predetermined internal rate of return measure accreted using the effective interest method to the redemption value as of the reporting date. Net Income (Loss) Attributable to Genesis Energy, L.P. for the ~~three~~ ~~months ended~~ ~~September 30, 2020~~2021 Quarter includes ~~$4.2~~$4.8 million of adjustments, of which ~~$3.5~~$4.1 million was allocated to the ~~PIK~~paid-in-kind ("PIK") distributions on the outstanding Alkali Holdings preferred units and $0.7 million was attributable to redemption accretion value adjustments. ~~Additionally,~~ Net Income (Loss) Attributable to Genesis Energy, L.P. for the ~~nine~~ ~~months ended~~ ~~September 30,~~ 2020 Quarter includes ~~$12.4~~$4.1 million of adjustments, of which ~~$10.2~~$3.3 million was allocated to the PIK distributions and ~~$2.2~~$0.8 million was attributable to redemption accretion value adjustments. We elected to pay distributions for the period ended ~~September 30, 2020~~March 31, 2021 in-kind to our Alkali Holdings preferred unitholders. The unitholders liquidation preference is increased by new issuances and these PIK distributions and is reduced by tax distributions paid to the unitholders, which are

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~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

required to be paid by us to ~~fulfull~~fulfill the income tax liabilities of each holder of Alkali Holdings preferred ~~units, paid to the unitholders.~~units.

As of the reporting date, there are no triggering, change of control, early redemption or monetization events that are probable that would require us to revalue the Alkali Holdings preferred units.

If the Alkali Holdings preferred units were redeemed on the reporting date of ~~September 30, 2020,~~March 31, 2021, the redemption amount would be equal to ~~$194.8~~$212.9 million, which would be the multiple of invested capital metric applied to the Alkali Holdings preferred units outstanding plus the make-whole amount on the undrawn minimum Alkali Holdings preferred units.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the change in our redeemable noncontrolling interest balance from December 31, ~~2019~~2020 to ~~September 30, 2020:~~March 31, 2021:




Balance as of December 31, ~~2019~~2020	$	~~125,133~~141,194
Issuance of preferred units, net of issuance costs(1)	~~7,457~~19,561
PIK ~~distributions~~distribution	~~10,216~~4,093
Redemption accretion	~~2,178~~698
Tax distributions(1)	$		~~(7,509)~~(1,891)
Balance as of ~~September 30, 2020~~March 31, 2021	$	~~137,475~~163,655

(1) ~~In July 2020,~~During the 2021 Quarter, we ~~submitted a tax call notice to GSO and~~ issued ~~7,609~~1,860 Alkali Holdings preferred units to GSO to satisfy the company's obligation to pay tax distributions. Additionally, we issued 18,100 Alkali Holdings preferred units to GSO in the 2021 Quarter to continue to fund the expansion of our Granger facility.

11. Net Income (Loss) Per Common Unit

Basic net income per common unit is computed by dividing net income, after considering income attributable to our preferred unitholders, by the weighted average number of common units outstanding.

The dilutive effect of our Class A Convertible Preferred Units is calculated using the if-converted method. Under the if-converted method, these 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 ~~three and nine months ended September 30, 2020,~~2021 Quarter, the effect of the assumed conversion of the 25,336,778 Class A Convertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.

The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Net Income (Loss) Attributable to Genesis Energy L.P.	Net Income (Loss) Attributable to Genesis Energy L.P.	$	(29,717)	$	17,557	$	(331,522)	$	73,631	Net Income (Loss) Attributable to Genesis Energy L.P.		$	(34,224)	$	24,909
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(18,684)		(18,684)		(56,052)		(55,783)		Less: Accumulated distributions attributable to Class A Convertible Preferred Units		(18,684)		(18,684)
Net Income (Loss) Available to Common Unitholders	Net Income (Loss) Available to Common Unitholders	$	(48,401)	$	(1,127)	$	(387,574)	$	17,848	Net Income (Loss) Available to Common Unitholders		$	(52,908)	$	6,225

Weighted Average Outstanding Units	Weighted Average Outstanding Units	122,579		122,579		122,579		122,579		Weighted Average Outstanding Units		122,579		122,579

Basic and Diluted Net Income (Loss) per Common Unit	Basic and Diluted Net Income (Loss) per Common Unit	$	(0.39)	$	(0.01)	$	(3.16)	$	0.15	Basic and Diluted Net Income (Loss) per Common Unit		$	(0.43)	$	0.05

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. Business Segment Information

We currently manage our businesses through 4 divisions that constitute our reportable segments:

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

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

•Onshore facilities and transportation – terminalling, blending, storing, marketing and transporting crude oil and 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 gains and charges, such as depreciation, depletion, amortization and accretion), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation plan and includes the non-income portion of payments received under the previously owned direct financing ~~leases.~~lease.

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment.

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~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Segment information for the periods presented below was as follows:

Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total
Three Months Ended September 30, 2020
Segment margin (a) $ 57,380 $ 27,592 $ 61,298 $ 15,587 $ 161,857
Capital expenditures (b) $ 2,899 $ 19,225 $ 1,446 $ 5,273 $ 28,843
Revenues:
External customers $ 53,870 $ 208,909 $ 130,440 $ 49,906 $ 443,125
Intersegment (c) 23 (2,178) 149 2,006 $ 0
Total revenues of reportable segments $ 53,893 $ 206,731 $ 130,589 $ 51,912 $ 443,125
Three Months Ended September 30, 2019
Segment margin (a) $ 81,060 $ 55,258 $ 24,829 $ 14,672 $ 175,819
Capital expenditures (b) $ 1,996 $ 26,415 $ 1,599 $ 12,741 $ 42,751
Revenues:
External customers $ 79,738 $ 279,416 $ 205,913 $ 56,630 $ 621,697
Intersegment (c) 0 (1,889) (885) 2,774 $ 0
Total revenues of reportable segments $ 79,738 $ 277,527 $ 205,028 $ 59,404 $ 621,697
Nine Months Ended September 30, 2020
Segment Margin (a) $ 217,774 $ 89,357 $ 110,612 $ 52,727 $ 470,470
Capital expenditures (b) $ 5,909 $ 67,662 $ 3,432 $ 22,998 $ 100,001
Revenues:
External customers $ 197,263 $ 648,987 $ 361,929 $ 163,336 $ 1,371,515
Intersegment (c) 23 (6,242) (1,423) 7,642 $ 0
Total revenues of reportable segments $ 197,286 $ 642,745 $ 360,506 $ 170,978 $ 1,371,515
Nine Months Ended September 30, 2019
Segment Margin (a) $ 233,978 $ 171,602 $ 86,352 $ 41,563 $ 533,495
Capital expenditures (b) $ 4,975 $ 75,258 $ 5,383 $ 29,665 $ 115,281
Revenues:
External customers $ 236,482 $ 833,278 $ 640,716 $ 166,015 $ 1,876,491
Intersegment (c) 0 (5,659) (3,086) 8,745 $ 0
Total revenues of reportable segments $ 236,482 $ 827,619 $ 637,630 $ 174,760 $ 1,876,491

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~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Total assets by reportable segment were as follows:~~

September 30,
2020 December 31,
2019
Offshore pipeline transportation $ 2,202,649 $ 2,306,946
Sodium minerals and sulfur services 1,959,863 2,019,905
Onshore facilities and transportation 1,027,353 1,457,190
Marine transportation 724,929 772,383
Other assets 38,556 41,217
Total consolidated assets $ 5,953,350 $ 6,597,641


	Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Onshore Facilities & Transportation		Marine Transportation		Total














Three Months Ended March 31, 2021
Segment Margin (a)	$	84,269	$	43,720	$	20,999	$	7,109	$	156,097
Capital expenditures (b)	$	11,528	$	10,038	$	1,099	$	11,714	$	34,379
Revenues:
External customers	$	64,384	$	229,306	$	188,150	$	39,379	$	521,219
Intersegment (c)	0		(2,019)		1,067		952		$	0
Total revenues of reportable segments	$	64,384	$	227,287	$	189,217	$	40,331	$	521,219
Three Months Ended March 31, 2020
Segment Margin (a)	$	85,246	$	36,941	$	28,099	$	19,002	$	169,288
Capital expenditures (b)	$	1,027	$	14,975	$	1,157	$	14,232	$	31,391
Revenues:
External customers	$	78,429	$	245,535	$	156,799	$	59,160	$	539,923
Intersegment (c)	0		(2,145)		(1,041)		3,186		$	0
Total revenues of reportable segments	$	78,429	$	243,390	$	155,758	$	62,346	$	539,923

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

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

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Total assets by reportable segment were as follows:


	March 31, 2021		December 31, 2020
Offshore pipeline transportation	$	2,169,156	$	2,187,083
Sodium minerals and sulfur services	1,958,893		1,962,146
Onshore facilities and transportation	1,065,316		1,035,662
Marine transportation	715,404		711,058
Other assets	40,844		37,670
Total consolidated assets	$	5,949,613	$	5,933,619

Reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P.:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Total Segment Margin	Total Segment Margin	$	161,857	$	175,819	$	470,470	$	533,495	Total Segment Margin		$	156,097	$	169,288
Corporate general and administrative expenses	Corporate general and administrative expenses	(10,801)		(15,276)		(42,160)		(39,878)		Corporate general and administrative expenses		(11,152)		(6,492)
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	(70,203)		(87,209)		(228,761)		(233,250)		Depreciation, depletion, amortization and accretion		(68,997)		(75,978)
Interest expense	Interest expense	(51,312)		(54,673)		(157,895)		(165,881)		Interest expense		(57,829)		(54,965)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	(2,318)		(7,682)		(14,500)		(18,185)		Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)		(8,856)		(6,406)
Other non-cash items (2)	Other non-cash items (2)	7,712		9,880		16,489		(7,223)		Other non-cash items (2)		(18,444)		33,261
Cash payments from direct financing leases in excess of earnings (3)		(44,088)		(2,131)		(48,620)		(6,238)
Cancellation of debt income (4)		809		0		20,534		0
Distribution from unrestricted subsidiaries not included in income (3)										Distribution from unrestricted subsidiaries not included in income (3)		(17,500)		(2,238)

Loss on extinguishment of debt (4)	Loss on extinguishment of debt (4)	0		0		(23,480)		0		Loss on extinguishment of debt (4)		(1,627)		(23,480)
Differences in timing of cash receipts for certain contractual arrangements (5)	Differences in timing of cash receipts for certain contractual arrangements (5)	(13,052)		(1,249)		(29,180)		10,886		Differences in timing of cash receipts for certain contractual arrangements (5)		(299)		(4,490)
Impairment expense (6)		(3,331)		0		(280,826)		0

Provision for leased items no longer in use	Provision for leased items no longer in use	(696)		461		(624)		833		Provision for leased items no longer in use		(604)		130
Redeemable noncontrolling interest redemption value adjustments ~~(7)~~(6)	Redeemable noncontrolling interest redemption value adjustments ~~(7)~~(6)	(4,149)		(272)		(12,394)		(272)		Redeemable noncontrolling interest redemption value adjustments ~~(7)~~(6)		(4,791)		(4,086)
Income tax expense		(145)		(111)		(575)		(656)
Income tax (expense) benefit										Income tax (expense) benefit		(222)		365
Net income (loss) attributable to Genesis Energy, L.P.	Net income (loss) attributable to Genesis Energy, L.P.	$	(29,717)	$	17,557	$	(331,522)	$	73,631	Net income (loss) attributable to Genesis Energy, L.P.		$	(34,224)	$	24,909

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

(2) The ~~three~~2021 Quarter and ~~nine months ended September 30,~~ 2020 Quarter include a ~~$6.7~~$18.4 million unrealized ~~gain~~loss and ~~$17.4~~$32.5 million unrealized gain, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. ~~The three and nine months ended September 30, 2019 include a $8.0 million unrealized gain and $0.3 million unrealized gain, respectively, from the valuation of the embedded derivative.~~ Refer to Note 16 for details.

(3) ~~Represents the net effect of adding~~The 2021 Quarter and 2020 Quarter include $17.5 million and $2.2 million, respectively, in cash receipts ~~from direct financing leases~~not included in income associated with principal repayments on our previously owned NEJD pipeline. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit facility. See N ote 4 for details.

(4) The 2021 Quarter includes the transaction costs and ~~deducting expenses relating to direct financing leases. The~~write-off of the ~~three and nine months ended September 30, 2020 include the cash we received~~unamortized issuance costs associated with the ~~exercise~~redemption of ~~a letter~~our remaining 2023 Notes. The 2020 Quarter includes the transaction costs associated with the tender and redemption of ~~credit we had issued to us as beneficiary from a customer that defaulted under~~ our ~~agreement.~~

~~(4)~~2022 Notes, along with the write-off of the unamortized issuance costs and discount associated with these notes. Refer to Note 9 for ~~details surrounding the extinguishment of our 2022 notes and note repurchases.~~details.

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

(6) ~~Refer to~~ ~~Note 6~~ ~~for details surrounding impairment expense.~~

~~(7)~~ Includes PIK distributions attributable to the period and accretion on the redemption feature.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. Transactions with Related Parties

The transactions with related parties were as follows:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Revenues:	Revenues:									Revenues:

Revenues from services and fees to Poseidon(1)	Revenues from services and fees to Poseidon(1)	$	3,102	$	3,019	$	9,284	$	9,420	Revenues from services and fees to Poseidon(1)		$	3,786	$	3,147
Revenues from product sales to ANSAC	Revenues from product sales to ANSAC	44,095		99,878		165,869		272,341		Revenues from product sales to ANSAC		67,955		73,079

Costs and expenses:	Costs and expenses:									Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	495	$	495	Amounts paid to our CEO in connection with the use of his aircraft		$	165	$	165
Charges for services from Poseidon(1)	Charges for services from Poseidon(1)	231		240		734		742		Charges for services from Poseidon(1)		240		254
Charges for services from ANSAC	Charges for services from ANSAC	528		1,020		1,989		3,356		Charges for services from ANSAC		178		832

(1)We own a 64% interest in Poseidon

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.

Poseidon

~~At September 30, 2020 and December 31, 2019, Poseidon owed us $1.9 million and $2.4 million, respectively, for services rendered.~~

We are the operator of Poseidon and 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 ~~three~~2021 Quarter and ~~nine months ended September 30,~~ 2020 Quarter reflect ~~$2.3~~$2.4 million and ~~$6.8 million, respectively. Our revenues for the three and nine months ended September 30, 2019 reflect $2.2 million and $6.7~~$2.3 million, respectively, of fees we earned through the provision of services under that agreement. At March 31, 2021 and December 31, 2020, Poseidon owed us $1.5 million and $2.6 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 our Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport.

ANSAC is considered a variable interest entity (VIE) because we experience certain risks and rewards from our relationship with ~~it.~~them. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC. The ANSAC membership agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. As of ~~September 30, 2020,~~March 31, 2021, such amount is not ~~estimable.~~material to us.

Net Sales to ANSAC were ~~$44.1 million and $165.9~~$68.0 million during the ~~three and nine months ended September 30, 2020~~2021 Quarter and were ~~$99.9 million and $272.3~~$73.1 million during the ~~three and nine months ended September 30, 2019.~~2020 Quarter. The costs charged to us by ANSAC, included in operating costs, were ~~$0.5 million and $2.0~~$0.2 million during the ~~three and nine months ended September 30, 2020~~2021 Quarter and were ~~$1.0 million and $3.4~~$0.8 million during the ~~three and nine months ended September 30, 2019.~~2020 Quarter.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Receivables from and payables to ANSAC as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 are as follows:


		September 30,		December 31,			March 31,		December 31,
		2020		2019			2021		2020
Receivables:	Receivables:					Receivables:
ANSAC	ANSAC	$	26,106	$	68,075	ANSAC	$	52,972	$	43,400
Payables:	Payables:					Payables:
ANSAC	ANSAC	$	305	$	2,103	ANSAC	$	349	$	470

14. Supplemental Cash Flow Information

The following table provides information regarding the net changes in components of operating assets and liabilities.


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
(Increase) decrease in:	(Increase) decrease in:					(Increase) decrease in:
Accounts receivable	Accounts receivable	$	165,505	$	6,294	Accounts receivable	$	(99,504)	$	101,405
Inventories	Inventories	(24,674)		709		Inventories	27,450		(5,024)
Deferred charges	Deferred charges	17,616		135		Deferred charges	7,731		2,783
Other current assets	Other current assets	(1,620)		(10,358)		Other current assets	(2,294)		(3,746)
Increase (decrease) in:	Increase (decrease) in:					Increase (decrease) in:
Accounts payable	Accounts payable	(59,477)		46,530		Accounts payable	38,994		(62,365)
Accrued liabilities	Accrued liabilities	(25,204)		(48,954)		Accrued liabilities	22,561		(25,519)
Net changes in components of operating assets and liabilities	Net changes in components of operating assets and liabilities	$	72,146	$	(5,644)	Net changes in components of operating assets and liabilities	$	(5,062)	$	7,534

Payments of interest and commitment fees were ~~$138.3~~$35.4 million and ~~$145.4~~$33.7 million for the ~~nine months ended September 30,~~2021 Quarter and 2020 ~~and September 30, 2019,~~Quarter, respectively. We capitalized interest of ~~$1.4~~$0.7 million and ~~$2.9~~$0.5 million during the ~~nine months ended September 30,~~2021 Quarter and 2020 ~~and September 30, 2019,~~Quarter, respectively.

At ~~September 30,~~March 31, 2021 and March 31, 2020, ~~and September 30, 2019,~~ we had incurred liabilities for fixed and intangible asset additions totaling ~~$26.5~~$27.1 million and ~~$17.7~~$17.2 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

15. 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 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Unaudited Condensed Consolidated Statements of Operations.

In accordance with NYMEX requirements, we fund the margin associated with our 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 Unaudited Condensed Consolidated Balance Sheets.

Additionally, we enter into swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales.

At ~~September 30, 2020,~~March 31, 2021, we entered into the following outstanding derivative commodity contracts to economically hedge inventory or fixed price purchase commitments.


		Sell (Short) Contracts		Buy (Long) Contracts			Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:	Designated as hedges under accounting rules:					Designated as hedges under accounting rules:
Crude oil futures:	Crude oil futures:					Crude oil futures:
Contract volumes (1,000 bbls)	Contract volumes (1,000 bbls)	444		0		Contract volumes (1,000 bbls)	92		0
Weighted average contract price per bbl	Weighted average contract price per bbl	$	38.55	$	0	Weighted average contract price per bbl	$	56.75	$	0

Not qualifying or not designated as hedges under accounting rules:	Not qualifying or not designated as hedges under accounting rules:					Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:	Crude oil futures:					Crude oil futures:
Contract volumes (1,000 bbls)	Contract volumes (1,000 bbls)	495		312		Contract volumes (1,000 bbls)	411		318
Weighted average contract price per bbl	Weighted average contract price per bbl	$	41.36	$	42.97	Weighted average contract price per bbl	$	59.47	$	60.42
Natural gas swaps:	Natural gas swaps:					Natural gas swaps:
Contract volumes (10,000 MMBTU)	Contract volumes (10,000 MMBTU)	274		0		Contract volumes (10,000 MMBTU)	46		0
Weighted average price differential per MMBTU	Weighted average price differential per MMBTU	$	0.27	$	0	Weighted average price differential per MMBTU	$	0.47	$	0
Natural gas futures:	Natural gas futures:					Natural gas futures:
Contract volumes (10,000 MMBTU)	Contract volumes (10,000 MMBTU)	92		318		Contract volumes (10,000 MMBTU)	90		126
Weighted average contract price per MMBTU	Weighted average contract price per MMBTU	$	2.25	$	2.48	Weighted average contract price per MMBTU	$	2.56	$	2.55

Fuel oil futures:
Contract volumes (1,000 bbls)		15		20
Weighted average contract price per bbl		$	37.10	$	37.05

Crude oil options:	Crude oil options:					Crude oil options:
Contract volumes (1,000 bbls)	Contract volumes (1,000 bbls)	33		13		Contract volumes (1,000 bbls)	16		0
Weighted average premium received/paid	Weighted average premium received/paid	$	0.82	$	0.15	Weighted average premium received/paid	$	4.68	$	0

Financial Statement Impacts

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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:

Fair Value of Derivative Assets and Liabilities


		Unaudited Condensed Consolidated Balance Sheets Location	Fair Value					Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
			September 30, 2020		December 31, 2019				March 31, 2021		December 31, 2020
Asset Derivatives:	Asset Derivatives:						Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):	Commodity derivatives - futures and call options (undesignated hedges):						Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Gross amount of recognized assets	Current Assets - Other	$	1,139	$	207	Gross amount of recognized assets	Current Assets - Other	$	243	$	732
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(1,139)		(207)		Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(243)		(732)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives	Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0	Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0
Natural Gas Swap (undesignated hedge)	Natural Gas Swap (undesignated hedge)	Current Assets - Other	1,145		1,382		Natural Gas Swap (undesignated hedge)	Current Assets - Other	127		616
Commodity derivatives - futures and call options (designated hedges):	Commodity derivatives - futures and call options (designated hedges):						Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Gross amount of recognized assets	Current Assets - Other	$	690	$	4	Gross amount of recognized assets	Current Assets - Other	$	670	$	1,022
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(690)		(4)		Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(670)		(1,022)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives	Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0	Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0
Liability Derivatives:	Liability Derivatives:						Liability Derivatives:
Preferred Distribution Rate Reset Election (2)	Preferred Distribution Rate Reset Election (2)	Other long-term liabilities	(34,120)		(51,515)		Preferred Distribution Rate Reset Election (2)	Other long-term liabilities	(70,810)		(52,372)
Natural Gas Swap (undesignated hedge)	Natural Gas Swap (undesignated hedge)	Accrued Liabilities	0		0		Natural Gas Swap (undesignated hedge)	Current Liabilities -Accrued Liabilities	0		0
Commodity derivatives - futures and call options (undesignated hedges):	Commodity derivatives - futures and call options (undesignated hedges):						Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Gross amount of recognized liabilities	Current Assets - Other (1)	$	(568)	$	(2,079)	Gross amount of recognized liabilities	Current Assets - Other (1)	$	(505)	$	(2,114)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other (1)	568		1,064		Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other (1)	505		2,114
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives	Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	(1,015)	Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0
Commodity derivatives - futures and call options (designated hedges):	Commodity derivatives - futures and call options (designated hedges):						Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities	Gross amount of recognized liabilities	Current Assets - Other (1)	$	(1,428)	$	(50)	Gross amount of recognized liabilities	Current Assets - Other (1)	$	(892)	$	(3,345)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other (1)	1,428		50		Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other (1)	892		3,073
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives	Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	0	Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	0	$	(272)

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

(2) Refer to Note 10 and Note 16 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of ~~September 30,~~March 31, 2021, we had a net broker receivable of approximately $1.8 million (consisting of initial margin of $1.1 million increased by $0.7 million of variation margin). As of December 31, 2020, we had a net broker receivable of approximately ~~$4.6~~$3.4 million (consisting of initial margin of ~~$4.0 million increased by $0.6 million of variation margin). As of December 31, 2019, we had a net broker receivable of approximately $0.9 million (consisting of initial margin of $0.8~~$3.3 million increased by $0.1 million of variation margin). At ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, 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 Class A Convertible Preferred Units may make a one-time election to reset the quarterly distribution amount (a "Rate Reset Election") to a cash amount per Class A Convertible Preferred Unit equal to the amount that would be payable per quarter if a Class A Convertible Preferred Unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. The Rate Reset Election of our Class A Convertible Preferred Units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Unaudited Condensed Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other income, net in our Unaudited Condensed Consolidated Statement of Operations. At ~~September 30, 2020,~~March 31, 2021, the fair value of this embedded derivative was a liability of ~~$34.1~~$70.8 million. See Note 10 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											Amount of Gain (Loss) Recognized in Income
		Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,					Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended March 31,
			2020		2019		2020		2019					2021		2020
Commodity derivatives - futures and call options:	Commodity derivatives - futures and call options:										Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs	$	(854)	$	227	$	(11,061)	$	(492)	Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs		$	(5,897)	$	729
Contracts not considered hedges under accounting guidance	Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs	1,175		1,373		(2,842)		(6,718)		Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, Sodium minerals and sulfur services operating costs		(3,921)		(1,375)
Total commodity derivatives	Total commodity derivatives		$	321	$	1,600	$	(13,903)	$	(7,210)	Total commodity derivatives			$	(9,818)	$	(646)

Natural Gas Swap Liability	Natural Gas Swap Liability	Sodium minerals and sulfur services operating costs	$	666	$	81	$	1,217	$	1,316	Natural Gas Swap Liability	Sodium minerals and sulfur services operating costs		$	(67)	$	(432)

Preferred Distribution Rate Reset Election	Preferred Distribution Rate Reset Election	Other income, net	$	6,689	$	7,974	$	17,395	$	306	Preferred Distribution Rate Reset Election	Other income (expense)		$	(18,438)	$	32,545

16. 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.


		Fair Value at						Fair Value at							Fair Value at						Fair Value at
		September 30, 2020						December 31, 2019							March 31, 2021						December 31, 2020
Recurring Fair Value Measures	Recurring Fair Value Measures	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3		Recurring Fair Value Measures	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Commodity derivatives:	Commodity derivatives:													Commodity derivatives:
Assets	Assets	$	1,829	$	1,145	$	0	$	211	$	1,382	$	0	Assets	$	913	$	127	$	0	$	1,754	$	616	$	0
Liabilities	Liabilities	$	(1,996)	$	0	$	0	$	(2,129)	$	0	$	0	Liabilities	$	(1,397)	$	0	$	0	$	(5,459)	$	0	$	0
Preferred Distribution Rate Reset Election	Preferred Distribution Rate Reset Election	$	0	$	0	$	(34,120)	$	0	$	0	$	(51,515)	Preferred Distribution Rate Reset Election	$	0	$	0	$	(70,810)	$	0	$	0	$	(52,372)

Rollforward of Level 3 Fair Value Measurements

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


	~~Nine~~Three Months Ended ~~September 30,~~March 31,
	~~2020~~2021
Balance as of December 31, ~~2019~~2020	$	~~(51,515)~~(52,372)
Unrealized ~~gain~~loss for the period included in earnings	~~17,395~~ (18,438)

Balance as of ~~September 30, 2020~~March 31, 2021	$	~~(34,120)~~(70,810)

Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy. The fair value of the swaps contracts was determined using market price quotations and a pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at ~~September 30, 2020.~~March 31, 2021.

The fair value of the embedded derivative feature is based on a valuation model that estimates the fair value of our Class A Convertible Preferred Units with and without a Rate Reset Election. This model contains inputs, including our common unit price relative to the issuance price, the current dividend yield, credit spread, default probabilities, equity volatility and timing estimates which involve management judgment. Our equity volatility rate used to value our embedded derivative feature was 50% at ~~September 30, 2020.~~March 31, 2021. 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. Due to a decrease in our discount yield compared to the preceding quarter, as well as the passage of time as we draw nearer to our coupon rate reset date in 2022, we recorded an unrealized loss of $18.4 million for the 2021 Quarter. During the 2020 Quarter, we recorded an unrealized gain of $32.5 million due to the significant changes ~~and fluctuations~~ in the energy industry credit markets and our common unit price during the ~~period, we recorded an~~period. The unrealized loss in the 2021 Quarter and the unrealized gain ~~of $6.7 million and $17.4 million, respectively, for~~in the ~~three and nine months ended September 30, 2020. These effects~~2020 Quarter are recorded within "Other income ~~net"~~(expense)" on the Unaudited Condensed Consolidated Statements of Operations.

See Note 15 for additional information on our derivative instruments.

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 ~~September 30, 2020~~March 31, 2021 our senior unsecured notes had a carrying value ~~of $2.4 billion~~ and fair value of ~~$2.1~~$2.7 billion compared to a carrying value of $2.8 billion and fair value of ~~$2.5~~$2.7 billion at December 31, ~~2019.~~2020. 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

17. Commitments and Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to aid in monitoring compliance and detecting and addressing releases of crude oil from our pipelines or other facilities and from our mining operations relating to our Alkali Business; however, no assurance can be made that such environmental releases may not substantially affect our business.

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.

18. Subsequent Events

On ~~October 30, 2020,~~April 8, 2021, we ~~reached~~entered into the Fifth Amended and Restated Credit Agreement (our "new credit agreement") to replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprising a term loan facility of $300 million and a revolving loan facility of $650 million, with the ability to increase the aggregate size of the revolving loan facility by an additional $200 million subject to lender consent and certain other customary conditions. The new credit agreement ~~with a subsidiary~~matures on March 15, 2024, subject to extension at our request for one additional year on up to 2 occasions and subject to certain conditions.

On April 22, 2021 we completed our offering of ~~Denbury Inc. to transfer to them the ownership~~an additional $250 million in aggregate principal amount of our ~~remaining CO2 assets, including~~2027 Notes. The additional notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms as (other than with respect to the ~~NEJD~~issue price) and ~~Free State pipelines. As a~~constitute part of the ~~agreement,~~same series of the 2027 Notes we ~~will receive total consideration of $92.5~~issued on December 17, 2020. The $250 million of ~~which $22.5 million was paid in~~ the ~~fourth quarter~~2027 Notes were issued at a premium of ~~2020 upon execution~~103.75%, plus accrued interest from December 17, 2020. We intend to use the net proceeds from the offering for general partnership purposes, including repaying a portion of the agreement, and the remaining $70 million will be paid in equal installments in each quarter during 2021. We will record a loss of approximately $21.5 million in the fourth quarter which represents the difference between the proceeds and the net book value of the assets transferred.revolving borrowings outstanding under our new revolving loan facility.

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

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~2020.

Included in Management’s Discussion and Analysis of Financial Condition and Results of Operations are the following sections:

•Overview

•Results of Operations

•Liquidity and Capital Resources

•Guarantor Summarized Financial Information

•Non-GAAP Financial Measures

•Commitments and Off-Balance Sheet Arrangements

•Forward Looking Statements

Overview

We reported Net Loss Attributable to Genesis Energy, L.P. of ~~$29.7~~$34.2 million during the ~~three months ended September 30, 2020 (“2020 Quarter”)~~2021 Quarter compared to Net Income Attributable to Genesis Energy, L.P. of ~~$17.6~~$24.9 million during the ~~three months ended September 30, 2019 (“2019 Quarter”).~~2020 Quarter. Net Loss Attributable to Genesis Energy, L.P. in the ~~2020~~2021 Quarter was ~~negatively~~ impacted, relative to the ~~2019~~2020 Quarter, by: (i) lower ~~segment margin~~Segment Margin of ~~$14.0~~$13.2 million, which is inclusive of approximately ~~$41~~$12.3 million of incremental cash receipts received in the ~~2020~~2021 Quarter ~~and included in the 2020 Quarter's segment margin,~~ associated with principal repayments on our ~~direct financing lease;~~previously owned NEJD pipeline not included in income and included in the 2021 Quarter's Segment Margin; and (ii) ~~lower non-cash revenues~~an unrealized loss from the valuation of ~~$11.8~~the embedded derivative associated with our Class A Convertible Preferred Units of $18.4 million in the 2021 Quarter compared to an unrealized gain of $32.5 million during the 2020 Quarter recorded within ~~our offshore pipeline transportation and onshore facilities and transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts.~~Other income (expense). These decreases were partially offset by (i) lower depreciation, depletion and amortization expense of ~~$15.8~~$8.1 million during the ~~2020~~2021 Quarter primarily due to lower depreciation expense on our rail logistics assets as they were impaired during the second quarter of ~~2020;~~2020, and (ii) ~~lower interest expense~~higher equity in earnings of ~~$3.4~~equity investees of $6.5 million during the ~~2020 Quarter.~~2021 Quarter primarily due to increased volumes on our 64% owned Poseidon oil pipeline.

Cash flow from operating activities was ~~$143.5~~$77.2 million for the 2021 Quarter compared to $89.6 million for the 2020 ~~Quarter compared to $136.1 million for the 2019~~ Quarter. This ~~increase~~decrease is primarily attributable to ~~positive working capital changes and higher payments received under our direct financing lease during~~lower Segment Margin of $13.2 million in the ~~2020 Quarter offset by lower revenues amongst our operating segments, which is discussed further below under "Results of Operations."~~2021 Quarter.

Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") to our common unitholders was ~~$70.7~~$54.6 million for the ~~2020~~2021 Quarter, a decrease of ~~$11.8~~$27.2 million, or ~~14.3%~~33.2%, from the ~~2019~~2020 Quarter, primarily due to ~~a decline~~lower Segment Margin of $13.2 million, as well as higher maintenance capital utilized, general and administrative expenses, and interest expense in ~~our reported Segment Margin.~~the 2021 Quarter. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Segment Margin (as defined below in "Non-GAAP Financial Measures") was ~~$161.9~~$156.1 million for the ~~2020~~2021 Quarter, a decrease of ~~$14.0~~$13.2 million, or 8%, from the ~~2019~~2020 Quarter. A more detailed discussion of our segment results and other costs is included below in "Results of Operations".

See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Distribution

In ~~October 2020,~~April 2021, we declared our quarterly distribution to our common unitholders of $0.15 per unit related to the ~~2020~~2021 Quarter. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.7374 per Class A Convertible Preferred Unit (or $2.9496 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on ~~November 13, 2020~~May 14, 2021 to unitholders of record at the close of business on ~~October~~April 30, ~~2020.~~2021.

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Covid-19 and Market Update

In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's CISA and we have continued to operate our assets during this pandemic.

We have a designated internal management team to provide resources, updates, and support to our entire workforce during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our employees, and the communities in which our businesses operate. We will continue to act in the best interests of our employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or local authorities as we continue to actively monitor the situation.

Covid-19 has caused commodity prices to ~~decline~~fluctuate due to, among other things, reduced industrial activity and travel demand that are expected to continue in the near future. Additionally, actions taken by OPEC and other oil exporting nations beginning in early March 2020 caused additional significant ~~declines and~~ volatility in the price of oil and gas. These ~~low and~~ volatile commodity prices are expected to continue at least for the near-term and possibly longer, reflecting fears of a global recession and potential further global economic damage from Covid-19, including factory shutdowns, travel bans, closings of schools and stores, and cancellations of conventions and similar events, resulting in, among other things, reduced fuel demand, lower manufacturing activity, and high inventories of oil, natural gas, and petroleum products, which could further negatively impact oil, natural gas, and petroleum products and industrial products.

Due to the economic effects from commodity prices and Covid-19, demand and volumes throughout our businesses were negatively impacted throughout 2020 beginning in the second quarter of 2020. As a result of lower current demand and the outlook for our crude-by-rail logistics assets, and rail becoming an uneconomic means of transportation for producers to get crude oil to their refineries, we identified a triggering event and subsequently recognized a non-cash impairment charge associated with these assets in our onshore facilities and transportation segmentquarter. Additionally, during ~~the second quarter of 2020.~~

~~During the~~ 2020, ~~Quarter, demand and volumes in~~ our businesses ~~continued to be~~were negatively impacted by ~~Covid-19~~lower refinery utilization, crude differentials, supply and demand imbalances in our Alkali Business, and an unprecedented hurricane season. However, we began to see economic recovery across a majority of our asset footprint as we exited 2020, which continued during the ~~economic effects from commodity prices. However,~~2021 Quarter. Specifically, during the 2021 Quarter, our offshore pipeline transportation segment experienced volumes at its normal run rate as we exited the ~~2020 Quarter, we believe we have begun to see a slight recovery~~quarter with our CHOPS pipeline back in ~~demand as certain regions~~service. Additionally, our Alkali Business sold out of the United States and the world slowly begin their re-opening phases. Specifically, in our sodium minerals and sulfur services operating segment, domestic and ANSAC volume demand and NaHS demand in South America have shown signs of recovery that we expect to continue into the fourth quarter of 2020 and into 2021.all production at its Westvaco facility.

~~However, we will~~We continue to monitor the market environment and will evaluate whether ~~additional~~any triggering events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions ~~further~~ deteriorate, we may identify ~~additional~~ triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in ~~further~~ impairment charges that could be material to our results of operations.

Although the potential future limitations and impact of Covid-19 are still unknown at this time, and although we tend to experience less demand for certain of our services and products when commodity prices decrease significantly over extended periods of time (and we expect a similar impact on demand when global restrictions are in place limiting the economy and industrial product use), we believe the fundamentals of our core businesses continue to remain strong and, given the current industry environment and capital market behavior, we have continued our focus on de-leveraging our balance sheet, which included the reduction of our distribution to common unitholders beginning in the first quarter of 2020 ~~. We also took~~and continuing to recognize the ~~opportunity to repurchase certain of~~benefits from our ~~senior unsecured notes on the open market and recorded a gain of $20.5 million, which allowed us to reduce our overall outstanding indebtedness and related interest charges. Additionally, during~~cost savings initiative in the second quarter of ~~2020, given~~2020. Additionally, subsequent to the ~~current operating environment~~2021 Quarter, we successfully refinanced and extended our ~~overall cost savings initiative, we recorded a one-time charge of approximately $13~~senior secured credit facility and issued an additional $250 million ~~associated with certain severance and restructuring expenses. We began to realize a portion~~in aggregate principal amount of our ~~estimated cost savings associated with this initiative during~~2027 Notes. These two events resulted in no scheduled maturities of long-term debt until 2024, other than the ~~2020 Quarter. During April 2020, we also amended our agreements with GSO associated with~~minimal quarterly payments due on the ~~expansion~~term loan component of our ~~Granger soda ash~~credit facility beginning at the end of 2021. Refer to ~~among other things, extend the construction timeline of the project by as much as one year.~~

"Liquidity and Capital Resources" for addition discussion.

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Results of Operations

Revenues and Costs and Expenses

Our revenues for the ~~2020~~2021 Quarter decreased ~~$178.6~~$18.7 million, or ~~29%~~3%, from the ~~2019~~2020 Quarter and our total costs and expenses ~~(excluding impairment expense)~~ as presented on the Unaudited Condensed Consolidated Statements of Operations ~~decreased $133.1~~increased $12.4 million, or ~~23%~~3%, between the two periods, with a net ~~change~~decrease to our operating income of ~~$45.5~~$31.1 million.

The decrease in our operating income during the 2021 Quarter is primarily driven by lower Segment Margin of $13.2 million, which is inclusive of approximately $12.3 million of incremental cash receipts received not included in income from our previously owned NEJD pipeline and incremental cash distributions received from our equity investees of $9.0 million. A more detailed discussion of our individual segment results is included in the section below, "Segment Margin." This was partially offset by lower depreciation, depletion, and amortization expense of $8.1 million during the 2021 Quarter primarily associated with our rail logistics assets, as they were impaired during the second quarter of 2020.

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil ~~and petroleum products~~ in our crude oil marketing business, which is included in ~~the~~our onshore facilities and transportation segment, and revenues and costs associated with our Alkali Business, which is included in ~~the~~our sodium minerals and sulfur services segment. The decrease in our revenues and our costs and expenses between the 2020 Quarter and the 2019 Quarter is primarily attributable to: (i) decreases in crude oil and petroleum product prices and, to an extent, sales volumes; and (ii) lower sales volumes in our sodium minerals and sulfur services segment due to lower economic and market demand as a result of Covid-19 and lower contractual export pricing as it relates to our Alkali Business. Additionally, our offshore transportation segment experienced lower volumes and revenue due to Hurricanes Laura and Marco which impacted our assets in the Gulf of Mexico during the 2020 Quarter, and also resulted in an increase to our operating expenses due to the costs incurred to perform the required inspections and analysis on our assets. Depreciation, depletion, and amortization expense was $15.8 million lower during the 2020 Quarter as compared to the 2019 Quarter due to lower depreciation expense associated with our rail logistics assets, as they were impaired during the second quarter of 2020. We describe, in more detail, the impact on revenues and costs for each of our businesses below.

As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") ~~decreased~~ ~~27%~~increased 25% to ~~$40.93~~$57.84 per barrel in the 2021 Quarter, as compared to $46.17 per barrel in the 2020 ~~Quarter, as compared to $56.42 per barrel in the 2019~~ Quarter. ~~Additionally, impacts~~Impacts from Covid-19 along with actions taken by OPEC and other oil exporting nations beginning in early ~~March~~ 2020 have caused ~~additional~~ significant price ~~declines and~~ volatility in oil and gas prices. ~~These low and volatile commodity prices are expected to continue at least for the near term and possibly longer.~~

We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin, ~~Net Income,~~net income, and Available Cash before Reserves. We have limited our direct commodity price exposure related to crude oil and petroleum products through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. However, we do have some indirect exposure to certain changes in prices for oil, natural gas, and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when commodity prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when commodity prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the section of our Annual Report entitled " Risks Related to Our Business."

As it relates to our Alkali Business, our revenues are derived from the extraction of trona, as well as the activities surrounding the processing and sale of natural soda ash and other alkali specialty products, including sodium sesquicarbonate (S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an industry-diverse and worldwide customer base. Our selling prices are contracted at various times throughout the year and for different durations. Typically, our selling prices for volumes sold internationally and through ANSAC are contracted for the current year (in a majority of cases, annually) in the prior December and January of the current year, and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. Our sales volumes can fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer demand and economic growth. Positive or negative changes to our revenue, through fluctuations in sales volumes or selling prices, can have a direct impact to Segment Margin, ~~Net Income~~net income and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, of which some are variable in nature and others are fixed in nature, relate primarily to the processing and producing of soda ash (and other alkali specialty products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during the ~~2020~~2021 Quarter as noted above, we had negative effects to our revenues (with a lesser impact to costs) due to lower sales volumes as a result of our Granger facility being put in a cold standby in 2020 and lower ~~export~~domestic pricing of soda ash during the ~~2020~~2021. During the 2021 Quarter, ~~as a result of~~we were able to generate cost efficiencies due to our cost savings initiative, and lower ~~economic~~energy consumption and ~~market demand.~~maintenance spending. For additional information, see our segment-by-segment analysis below.

In addition to our crude oil marketing business and Alkali Business discussed above, we continue to operate in our other core businesses including: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of ~~billions of~~a billion dollars) to develop numerous ~~large reservoir,~~large-reservoir, long-lived crude oil and natural gas properties; (ii) our sulfur services business, which is one of the ~~leading~~largest producers and marketers (based on tons produced) of NaHS in North and South America; and (iii) our

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onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of

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over 95% of the volumes transported on our onshore crude pipelines, and refiners contract for ~~over~~ ~~80%~~75% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. The shippers on our offshore pipelines are mostly integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in relatively low commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our ~~Net Income,~~net income, Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

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

Segment Margin

The contribution of each of our segments to total Segment Margin was as follows:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
Offshore pipeline transportation	Offshore pipeline transportation	$	57,380	$	81,060	$	217,774	$	233,978	Offshore pipeline transportation		$	84,269	$	85,246
Sodium minerals and sulfur services	Sodium minerals and sulfur services	27,592		55,258		89,357		171,602		Sodium minerals and sulfur services		43,720		36,941
Onshore facilities and transportation	Onshore facilities and transportation	61,298		24,829		110,612		86,352		Onshore facilities and transportation		20,999		28,099
Marine transportation	Marine transportation	15,587		14,672		52,727		41,563		Marine transportation		7,109		19,002
Total Segment Margin	Total Segment Margin	$	161,857	$	175,819	$	470,470	$	533,495	Total Segment Margin		$	156,097	$	169,288

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

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A reconciliation of total Segment Margin to Net Income (Loss) Attributable to Genesis Energy, L.P. for the periods presented is as follows:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Total Segment Margin	Total Segment Margin	$	161,857	$	175,819	$	470,470	$	533,495	Total Segment Margin		$	156,097	$	169,288
Corporate general and administrative expenses	Corporate general and administrative expenses	(10,801)		(15,276)		(42,160)		(39,878)		Corporate general and administrative expenses		(11,152)		(6,492)
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	(70,203)		(87,209)		(228,761)		(233,250)		Depreciation, depletion, amortization and accretion		(68,997)		(75,978)
Interest expense	Interest expense	(51,312)		(54,673)		(157,895)		(165,881)		Interest expense		(57,829)		(54,965)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	(2,318)		(7,682)		(14,500)		(18,185)		Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)		(8,856)		(6,406)
Other non-cash items (2)	Other non-cash items (2)	7,712		9,880		16,489		(7,223)		Other non-cash items (2)		(18,444)		33,261
Cash payments from direct financing leases in excess of earnings (3)		(44,088)		(2,131)		(48,620)		(6,238)
Cancellation of debt income		809		—		20,534		—
Distribution from unrestricted subsidiaries not included in income (3)										Distribution from unrestricted subsidiaries not included in income (3)		(17,500)		(2,238)

Provision for leased items no longer in use	Provision for leased items no longer in use	(696)		461		(624)		833		Provision for leased items no longer in use		(604)		130
Differences in timing of cash receipts for certain contractual arrangements (4)	Differences in timing of cash receipts for certain contractual arrangements (4)	(13,052)		(1,249)		(29,180)		10,886		Differences in timing of cash receipts for certain contractual arrangements (4)		(299)		(4,490)

Loss on debt extinguishment (5)	Loss on debt extinguishment (5)	—		—		(23,480)		—		Loss on debt extinguishment (5)		(1,627)		(23,480)
Impairment expense		(3,331)		—		(280,826)		—

Redeemable noncontrolling interest redemption value adjustments (6)	Redeemable noncontrolling interest redemption value adjustments (6)	(4,149)		(272)		(12,394)		(272)		Redeemable noncontrolling interest redemption value adjustments (6)		(4,791)		(4,086)
Income tax expense		(145)		(111)		(575)		(656)
Income tax (expense) benefit										Income tax (expense) benefit		(222)		365
Net Income (Loss) Attributable to Genesis Energy, L.P.	Net Income (Loss) Attributable to Genesis Energy, L.P.	$	(29,717)	$	17,557	$	(331,522)	$	73,631	Net Income (Loss) Attributable to Genesis Energy, L.P.		$	(34,224)	$	24,909

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

(2)The ~~three~~2021 Quarter and ~~nine months ended September 30,~~ 2020 Quarter include a ~~$6.7~~$18.4 million unrealized ~~gain~~loss and a ~~$17.4~~$32.5 million unrealized gain, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. ~~The three and nine months ended September 30, 2019 include a~~ ~~$8.0 million~~ ~~unrealized gain and a~~ ~~$0.3 million~~ ~~unrealized gain, respectively, from the valuation of the embedded derivative.~~

(3)~~Represents the net effect of adding~~The 2021 Quarter and 2020 Quarter include $17.5 million and $2.2 million, respectively, in cash receipts ~~from direct financing leases and deducting expenses relating to direct financing leases. The the three and nine months ended September 30, 2020 include the cash we received~~not included in income associated with ~~the exercise of a letter of credit we had issued to us~~principal repayments on our previously owned NEJD pipeline. Genesis NEJD Pipeline, LLC is defined as ~~beneficiary from a customer that defaulted~~an unrestricted subsidiary under our ~~agreement.~~credit facility.

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

(5)~~Includes~~The 2021 Quarter includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining 2023 Notes. The 2020 Quarter includes the transaction costs associated with the tender ~~of $527.9 million~~ and redemption ~~of $222.1 million~~ of our 2022 Notes, ~~in the first quarter of 2020, along with~~as well as the write-off of ~~our~~the unamortized issuance costs and discount associated with these notes.

(6) Includes PIK distributions attributable to the period and accretion on the redemption feature.

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Offshore Pipeline Transportation Segment

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues	Offshore crude oil pipeline revenue, excluding non-cash revenues	$	52,157	$	63,945	$	182,741	$	188,115	Offshore crude oil pipeline revenue, excluding non-cash revenues		$	62,662	$	69,581
Offshore natural gas pipeline revenue, excluding non-cash revenues	Offshore natural gas pipeline revenue, excluding non-cash revenues	8,166		17,043		31,805		41,391		Offshore natural gas pipeline revenue, excluding non-cash revenues		10,397		13,337
Offshore pipeline operating costs, excluding non-cash expenses	Offshore pipeline operating costs, excluding non-cash expenses	(19,221)		(19,002)		(50,963)		(52,240)		Offshore pipeline operating costs, excluding non-cash expenses		(18,006)		(17,732)
Distributions from equity investments (1)	Distributions from equity investments (1)	16,278		19,074		54,191		56,712		Distributions from equity investments (1)		29,216		20,060
Offshore pipeline transportation Segment Margin	Offshore pipeline transportation Segment Margin	$	57,380	$	81,060	$	217,774	$	233,978	Offshore pipeline transportation Segment Margin		$	84,269	$	85,246

Volumetric Data 100% basis:	Volumetric Data 100% basis:									Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):	Crude oil pipelines (average barrels/day unless otherwise noted):									Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	CHOPS	98,626		231,635		178,962		234,070		CHOPS		116,427		242,182
Poseidon	Poseidon	274,008		249,209		268,862		255,811		Poseidon		339,409		279,181
Odyssey	Odyssey	84,902		144,995		117,100		148,945		Odyssey		138,445		149,440
GOPL (3)		1,266		9,796		3,706		10,046
GOPL (2)										GOPL (2)		6,776		7,249
Total crude oil offshore pipelines	Total crude oil offshore pipelines	458,802		635,635		568,630		648,872		Total crude oil offshore pipelines		601,057		678,052

Natural gas transportation volumes (MMBtus/d)	Natural gas transportation volumes (MMBtus/d)	265,465		396,408		337,039		420,595		Natural gas transportation volumes (MMBtus/d)		325,669		416,564

Volumetric Data net to our ownership interest (2):
Volumetric Data net to our ownership interest (3):										Volumetric Data net to our ownership interest (3):
Crude oil pipelines (average barrels/day unless otherwise noted):	Crude oil pipelines (average barrels/day unless otherwise noted):									Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	CHOPS	98,626		231,635		178,962		234,070		CHOPS		116,427		242,182
Poseidon	Poseidon	175,365		159,494		172,072		163,719		Poseidon		217,222		178,676
Odyssey	Odyssey	24,622		42,049		33,959		43,194		Odyssey		40,149		43,338
GOPL (3)		1,266		9,796		3,706		10,046
GOPL (2)										GOPL (2)		6,776		7,249
Total crude oil offshore pipelines	Total crude oil offshore pipelines	299,879		442,974		388,699		451,029		Total crude oil offshore pipelines		380,574		471,445

Natural gas transportation volumes (MMBtus/d)	Natural gas transportation volumes (MMBtus/d)	83,833		151,864		112,501		162,396		Natural gas transportation volumes (MMBtus/d)		102,498		147,067

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in the 2021 Quarter and 2020 ~~and 2019,~~Quarter, respectively.

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

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

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Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~March 31, 2020

Offshore pipeline transportation Segment Margin for the ~~2020~~2021 Quarter decreased ~~$23.7~~$1.0 million, or ~~29%~~1%, from the ~~2019~~2020 Quarter, primarily due to lower overall volumes on our crude oil and natural gas pipeline ~~systems and a relative increase in operating costs. During~~systems. These lower volumes are primarily the ~~2020 Quarter, our Gulf of Mexico assets experienced unplanned downtime and interruption from Hurricanes Laura and Marco as a~~ result of producers shutting in during the storm and us taking the necessary precautions to remove all personnel from the platform assets that we operate and maintain. While the 2019 Quarter was negatively impacted by Hurricane Barry, the effects during the 2020 Quarter on our ~~assets were more significant and longer lasting. In addition to the majority of our assets being shut in for approximately one to two weeks, our 100% owned~~ CHOPS pipeline ~~although not damaged, has been~~being out of service ~~since August 26, 2020~~through February 3, 2021 due to damage at a junction platform that the ~~CHOPS~~ system goes up and over. We are currently in the process of undergoing the required regulatory inspections and analysis to address any platform issues caused by Hurricane Laura in an effort to safely return our assets to operation as soon as possible, and we incurred approximately $5 million of incremental operating costs in the 2020 Quarter associated with these efforts. During this time, we have successfully diverted all CHOPS barrels to our 64% owned and operated Poseidon oil pipeline system and expect to continue so during the fourth quarter of 2020. We expect volumes on our other offshore pipeline transportation assets to return to normal pre-hurricane levels in the fourth quarter of 2020, with the exception of unexpected downtime we incurred in October due to Hurricanes Delta and Zeta that impacted our operations by some 15 days.

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

Offshore pipeline transportation Segment Margin for the first nine months of 2020 decreased $16.2 million, or 7%, from the first nine months of 2019, primarily due to lower overall volumes on our crude oil and natural gas pipeline systems and a relative increase in operating costs. These lower volumes and higher operating costs are the results of: (i) unplanned downtime during 2020over as a result of ~~Tropical Storm Cristobal and Hurricanes Laura and Marco; (ii) planned downtime, which in some cases was extended due~~the 2020 hurricane season. On February 4, 2021, we placed the CHOPS pipeline back into service upon the installation of a bypass that allows our pipeline to operate around the ~~economic environment (primarily in~~junction platform. The lower CHOPS pipeline volumes during the second quarter of 2020); and (iii) the fact that the 2019 Segment Margin included volumes and margin contribution from one of our non-core gas pipelines that was abandoned near the end of 2019. These decreases2021 Quarter were partially offset by increased ~~volumes flowing~~distributions from ~~the Buckskin and Hadrian North production fields in 2020 (which had first oil towards the end of the second quarter of 2019), which is fully dedicated to~~ our ~~100% owned SEKCO pipeline, and further downstream,~~equity method investments, primarily associated with our 64% owned Poseidon oil pipeline ~~system.~~

system, as we were able to successfully divert CHOPS volumes to Poseidon during its out of service period. Additionally, we had higher volumes on our 100% owned SEKCO pipeline as a result of higher volumes from the Buckskin production field, which is fully dedicated to SEKCO and further downstream, Poseidon.

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Sodium Minerals and Sulfur Services Segment

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
Volumes sold:	Volumes sold:									Volumes sold:
NaHS volumes (Dry short tons "DST")	NaHS volumes (Dry short tons "DST")	28,105		26,806		80,129		97,076		NaHS volumes (Dry short tons "DST")		28,802		30,082
Soda Ash volumes (short tons sold)	Soda Ash volumes (short tons sold)	588,949		951,172		2,006,006		2,646,582		Soda Ash volumes (short tons sold)		762,820		822,247
NaOH (caustic soda) volumes (dry short tons sold)	NaOH (caustic soda) volumes (dry short tons sold)	20,922		18,844		57,551		60,171		NaOH (caustic soda) volumes (dry short tons sold)		20,262		16,303

Revenues (in thousands):	Revenues (in thousands):									Revenues (in thousands):
NaHS revenues, excluding non-cash revenues	NaHS revenues, excluding non-cash revenues	$	29,271	$	30,793	$	85,788	$	114,795	NaHS revenues, excluding non-cash revenues		$	30,136	$	33,191
NaOH (caustic soda) revenues	NaOH (caustic soda) revenues	9,256		9,644		25,341		32,202		NaOH (caustic soda) revenues		8,407		7,441
Revenues associated with Alkali Business	Revenues associated with Alkali Business	151,227		219,617		469,361		623,818		Revenues associated with Alkali Business		167,324		176,236
Other revenues	Other revenues	624		1,167		1,729		4,108		Other revenues		930		643
Total external segment revenues, excluding non-cash revenues(1)	Total external segment revenues, excluding non-cash revenues(1)	$	190,378	$	261,221	$	582,219	$	774,923	Total external segment revenues, excluding non-cash revenues(1)		$	206,797	$	217,511

Segment Margin (in thousands)	Segment Margin (in thousands)	$	27,592	$	55,258	$	89,357	$	171,602	Segment Margin (in thousands)		$	43,720	$	36,941

Average index price for NaOH per DST(2)	Average index price for NaOH per DST(2)	$	697	$	692	$	681	$	702	Average index price for NaOH per DST(2)		$	648	$	648

(1) Totals are for external revenues and costs prior to intercompany elimination upon consolidation.

(2) Source: IHS Chemical.

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~March 31, 2020

Sodium minerals and sulfur services Segment Margin for the ~~2020~~2021 Quarter ~~decreased $27.7~~increased $6.8 million, or ~~50%~~18%, from the ~~2019 Quarter,~~2020 Quarter. This increase is primarily due to increased production rates at our Westvaco facility and cost efficiencies recognized during the 2021 Quarter in our Alkali Business. Such cost efficiencies include favorable energy consumption, maintenance and other cost savings as implemented during the second quarter of 2020. These increases were partially offset by lower ~~volumes and~~domestic pricing in our Alkali ~~Business.~~Business and lower volumes reported during the period. During the ~~2020~~2021 Quarter, we ~~experienced~~reported lower ~~ANSAC and domestic sales~~NaHS volumes of soda ash relative to the 2019 Quarter due to the continued demand destruction from the worldwide economic shutdowns and uncertainty from the pandemic. This was coupled with lower export pricing due to supply and demand imbalances that existed at the time of our re-contracting phase in December 2019 and January 2020, which is expected to continue, to some extent, for at least the rest of 2020. While the soda ash volumes sold during the 2020 Quarter were relatively flat compared to the second quarter of 2020, we began to see an uptick in demand both domestically and on ANSAC volumes throughout the 2020 Quarter as certain regions of the world are beginning to re-open their economies and we expect continued demand recovery throughout the rest of 2020 and into 2021. In our refinery services business ~~we experienced a slight increase in NaHS volumes during the 2020 Quarter~~ due to ~~higher~~lower demand from ~~certain of~~ our ~~domestic pulp and paper customers. Additionally,~~mining customers, primarily in ~~South America (primarily in Peru),we began~~Peru. We have begun to see some recovery in demand from previous customer shut-ins amidst the spread of Covid-19 and our customer's production levels and we expect these volumes to continue recovering to their normal levels ~~throughout the rest of 2020.~~

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

~~Sodium minerals and sulfur services Segment Margin for the first nine months of 2020 decreased $82.2 million, or 48%. This decrease is primarily due to~~as we move through 2021. We also reported lower volumes and pricing in our Alkali Business and lower NaHS volumes in our refinery services business. In our Alkali Business, the nine months ended September 30, 2020 was negatively impacted by lower demand for our soda ash volumes ~~during 2020, primarily in the second and third quarters,~~ as a result of ~~economic shutdowns and uncertainty from~~our Granger facility being put in cold standby during the ~~Covid-19 pandemic. This was coupled with lower export pricing due to supply and demand imbalances that existed at the time~~second half of ~~our re-contracting phase in December 2019 and January 2020, which~~2020. Our Granger facility is expected to ~~continue, to some extent, for at least~~come back online during the ~~rest~~second half of 2020. In our refinery services business, we experienced a decline in NaHS volumes during 2020 due to lower demand from our mining customers in South America as a result of customer shut-ins, primarily in Peru, due to the spread of Covid-19 and we expect these volumes to return to normal levels later in 2020, and further2023 upon the ~~economy restrictions being lifted globally. This decline was coupled with lower demand from certain~~completion of our ~~domestic mining and pulp and paper customers throughout the nine months ended September 30, 2020.~~Granger facility expansion project.

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Onshore Facilities and Transportation Segment

Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks, railcars, and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals and rail facilities ~~and CO~~2 ~~pipelines~~ operating primarily within the United States Gulf Coast crude oil market. In addition, we utilize our railcar and trucking fleets that support the purchase and sale of gathered and bulk purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following:

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

•~~transporting CO~~2 ~~from natural and anthropogenic sources to crude oil fields owned by our customers;~~

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

•Unloading railcars at our crude-by-rail terminals;

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

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

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

We also use our terminal facilities to take advantage of contango market conditions, to gather and market crude oil, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products. When we purchase and store crude oil during periods of contango, we attempt to limit direct commodity price risk by simultaneously entering into a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. ~~During the 2020 Quarter, crude oil price markets were in contango, and we were able to use our available capacity to profit from this strategy during the period.~~

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills and assets to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

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

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
Gathering, marketing, and logistics revenue	Gathering, marketing, and logistics revenue	$	115,929	$	187,988	$	311,066	$	584,126	Gathering, marketing, and logistics revenue		$	178,562	$	135,307
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines		14,208		16,080		48,214		50,332
Payments received under direct financing leases not included in income		44,088		2,131		48,620		6,238
Crude oil and CO2 pipeline tariffs and revenues										Crude oil and CO2 pipeline tariffs and revenues		9,975		19,861
Distributions from unrestricted subsidiaries not included in income (1)										Distributions from unrestricted subsidiaries not included in income (1)		17,500		2,238
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(104,197)		(163,314)		(258,474)		(496,090)		Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions		(161,984)		(111,494)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	(15,895)		(20,466)		(52,265)		(57,455)		Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses		(15,266)		(18,493)
Other	Other	7,165		2,410		13,451		(799)		Other		(7,788)		680
Segment Margin	Segment Margin	$	61,298	$	24,829	$	110,612	$	86,352	Segment Margin		$	20,999	$	28,099

Volumetric Data (average barrels per day unless otherwise noted):	Volumetric Data (average barrels per day unless otherwise noted):									Volumetric Data (average barrels per day unless otherwise noted):
Onshore crude oil pipelines:	Onshore crude oil pipelines:									Onshore crude oil pipelines:
Texas	Texas	64,635		51,492		70,444		47,265		Texas		32,762		84,499
Jay	Jay	9,731		10,292		8,276		10,644		Jay		8,783		10,013
Mississippi	Mississippi	5,523		6,015		5,605		5,988		Mississippi		5,097		6,409
Louisiana ~~(1)~~(2)	Louisiana ~~(1)~~(2)	73,482		115,519		99,490		114,337		Louisiana ~~(1)~~(2)		120,726		162,736

Onshore crude oil pipelines total	Onshore crude oil pipelines total	153,371		183,318		183,815		178,234		Onshore crude oil pipelines total		167,368		263,657

CO2 pipeline (average Mcf/day):	CO2 pipeline (average Mcf/day):									CO2 pipeline (average Mcf/day):
Free State(3)	Free State(3)	90,649		76,914		106,530		86,294		Free State(3)		—		134,834

Crude oil and petroleum products sales:	Crude oil and petroleum products sales:									Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	Total crude oil and petroleum products sales	29,284		33,244		25,772		32,593		Total crude oil and petroleum products sales		31,462		26,118
Rail unload volumes	Rail unload volumes	3,860		78,696		33,907		87,745		Rail unload volumes		40,252		94,040

(1)The 2021 Quarter includes cash payments received from our previously owned NEJD pipeline of $17.5 million not included in income. 2020 includes cash payments received from the NEJD pipeline of $2.2 million not included in income.

(2) Total daily volume for the ~~three and nine months ended September 30, 2020 include 33,874 and 35,676~~2021 Quarter includes 24,837 barrels per day ~~respectively,~~ of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. Total daily volume for the ~~three and nine months ended September 30, 2019~~2020 Quarter includes ~~45,657 and 54,153~~44,322 barrels per day of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.

(3) The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020.

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~

~~Onshore facilities and transportation Segment Margin for the~~March 31, 2020 Quarter increased by $36.5 million, or 146.9%, from the 2019 Quarter primarily due to the 2020 Quarter including the receipt of a cash payment of approximately $41 million associated with the exercise of a letter of credit we had issued to us as beneficiary from a customer that defaulted under a twenty year term agreement. This increase was partially offset by lower volumes throughout our onshore facilities and transportation asset base, primarily in Louisiana at our Baton Rouge corridor assets and our Raceland rail facility. Due to the decline in crude oil prices and the collapse in the differential of Western Canadian Select (WCS) to the Gulf Coast, which has made crude-by-rail to the Gulf Coast uneconomic, the volumes at our Baton Rouge facilities were below our minimum take-or-pay levels and we were only able to recognize our minimum volume commitment in segment margin during the 2020 Quarter. We expect to only recognize our minimum volume commitment in segment margin through the rest of 2020 and as we enter 2021 due to the lower anticipated volumes and the prepaid transportation credits that our customer has accumulated over the last six months.

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

Onshore facilities and transportation Segment Margin for the ~~nine months ended September 30, 2020 increased $24.3~~2021 Quarter decreased $7.1 million, or ~~28.1%~~25%, primarily due ~~to:~~to lower volumes on our onshore pipeline and rail logistics assets. These lower volumes are the result of: (i) ~~2020 including~~lower rail unload and pipeline volumes in Louisiana due to lower utilization at the ~~receipt of a cash payment of approximately $41 million associated with the exercise of a letter of credit we had issued to us as beneficiary from a customer~~Gulf Coast refineries that ~~defaulted under a twenty year term agreement, and~~our assets serve; (ii) ~~higher~~lower volumes on our Texas ~~system~~pipeline primarily due to less receipts originating in the Gulf of Mexico from our CHOPS pipeline as it was out of service for a portion of the 2021 Quarter; and (iii) the divestiture of our Free State pipeline during the fourth quarter of 2020, which ~~is capable~~contributed positively to Segment Margin in the 2020 Quarter. These decreases were offset by higher cash receipts received during the 2021 Quarter from Denbury of ~~receiving and transporting barrels that~~approximately $12.3 million associated with our previously owned NEJD pipeline as a result of our agreement reached during the fourth quarter of 2020.

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originate in the Gulf of Mexico, including our 100% owned CHOPS pipeline, amongst others, to markets in Webster and Texas City. This was partially offset by the fact that the 2019 results included the receipt of a cash payment of $10 million associated with the resolution of a crude oil supply agreement and lower rail unload volumes during 2020 due to crude-by-rail to the Gulf Coast becoming uneconomic as a result of the decline in crude oil prices and the collapse in the differential of Western Canadian Select (WCS) to the Gulf Coast.

Marine Transportation Segment

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


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		2020			2019			2020			2019					2021			2020
Revenues (in thousands):	Revenues (in thousands):													Revenues (in thousands):
Inland freight revenues	Inland freight revenues	$	21,347		$	26,237		$	74,724		$	77,675		Inland freight revenues		$	17,515		$	27,572
Offshore freight revenues	Offshore freight revenues	21,132			19,975			64,491			56,547			Offshore freight revenues		14,526			21,091
Other rebill revenues (1)	Other rebill revenues (1)	9,433			13,192			31,763			40,538			Other rebill revenues (1)		8,290			13,683
Total segment revenues	Total segment revenues	$	51,912		$	59,404		$	170,978		$	174,760		Total segment revenues		$	40,331		$	62,346

Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	$	36,325		$	44,732		$	118,251		$	133,197		Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses		$	33,222		$	43,344

Segment Margin (in thousands)	Segment Margin (in thousands)	$	15,587		$	14,672		$	52,727		$	41,563		Segment Margin (in thousands)		$	7,109		$	19,002

Fleet Utilization: (2)	Fleet Utilization: (2)													Fleet Utilization: (2)
Inland Barge Utilization	Inland Barge Utilization	74.0		%	97.2		%	85.0		%	97.5		%	Inland Barge Utilization		72.0		%	93.4		%
Offshore Barge Utilization	Offshore Barge Utilization	95.7		%	92.4		%	97.3		%	94.2		%	Offshore Barge Utilization		95.7		%	99.4		%

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

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

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~March 31, 2020

Marine transportation Segment Margin for the ~~2020~~2021 Quarter ~~increased $0.9~~decreased $11.9 million, or 6%63%, from the ~~2019 Quarter. During the~~ 2020 ~~Quarter, in our offshore barge operation, we benefited from the continual improving rates in the spot and short term markets coupled with increased utilization relative to the 2019~~ Quarter. This ~~was partially offset by~~decrease is primarily attributable to lower utilization and day rates in our inland ~~business. We expect to see continued pressure on our utilization,~~business during the 2021 Quarter and ~~to an extent, the spot~~lower rates in our inland business as Midwest and Gulf Coast refineries continue to lower their utilization rates to better align with overall demand as a result of Covid-19 and the current operating environment. Additionally, the five year contract associated withoffshore barge operation, including our M/T American Phoenix tanker ended on September 30, 2020. We have re-contracted the tanker beginning in the fourth quarter of 2020 at a marginally lower rate and shorter term. We have continued to enter into short term contracts (less than a year) in both the inland and offshore (including the M/T American Phoenix) markets because we believe the day rates currently being offered by the market have yet to fully recover from their cyclical lows.

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

Marine transportation Segment Margin for the nine months ended September 30, 2020 increased $11.2 million, or 27%. During 2020, in our offshore barge operation, we benefited from the continual improving rates in the spot and short term markets coupled with increased utilization relative to 2019. In our inland business, 2020 day rates increased relative to 2019 over the nine month periods, which more than offset the lower utilization.tanker. We expect to see continued pressure on our utilization, and to an extent, the spot rates on our inland business as Midwest and Gulf Coast refineries ~~continue~~have continued to run at lower ~~their~~ utilization rates to better align with overall demand as a result of Covid-19 and the current operating environment. We have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market have yet to fully recover from their cyclical lows.

~~Table~~ We also re-contracted our M/T American Phoenix tanker beginning in the second quarter of ~~Contents~~

2021 through the first quarter of 2022 at a higher rate than the 2021 Quarter.

Other Costs, Interest, and Income Taxes

General and administrative expenses


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
General and administrative expenses not separately identified below:	General and administrative expenses not separately identified below:									General and administrative expenses not separately identified below:
Corporate	Corporate	$	9,846	$	9,856	$	44,003	$	30,384	Corporate		$	9,421	$	10,793
Segment	Segment	1,048		1,065		3,186		3,283		Segment		1,051		1,065
Long-term incentive compensation expense	Long-term incentive compensation expense	143		1,114		(1,387)		3,008		Long-term incentive compensation expense		1,080		(2,485)
Third party costs related to business development activities and growth projects	Third party costs related to business development activities and growth projects	35		2,964		56		3,422		Third party costs related to business development activities and growth projects		114		—
Total general and administrative expenses	Total general and administrative expenses	$	11,072	$	14,999	$	45,858	$	40,097	Total general and administrative expenses		$	11,666	$	9,373

Table of Contents

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with ~~Three~~March Months Ended ~~September 30, 2019~~March 31, 2020

Total general and administrative expenses for the ~~2020~~2021 Quarter ~~decreased~~increased by ~~$3.9~~$2.3 million primarily due to ~~the 2019 Quarter including third party transaction costs associated with the closing of our financing transaction for the Granger expansion. Additionally, the 2020 Quarter had lower~~higher long term incentive compensation expense ~~due to~~in the ~~assumptions used to value our outstanding awards for each respective period.~~

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

~~Total general and administrative expenses for the nine months ended September 30, 2020 increased by $5.8 million primarily due to the effects of~~2021 quarter as a one-time charge of approximately $13 million related to certain severance and restructuring expenses incurred during the second quarter of 2020. This was partially offset by lower long-term incentive compensation expense due to the effectresult of changes in assumptions used to value our outstanding awards between the two periods. This increase was partially offset by lower corporate general and ~~lower third party~~administrative costs ~~associated with business development activities and growth projects during 2020 as 2019 included costs associated with~~in the ~~closing of our financing transaction for the Granger expansion.~~

2021 Quarter.

Depreciation, depletion, and amortization expense


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
Depreciation and depletion expense	Depreciation and depletion expense	$	63,103	$	78,432	$	209,238	$	225,594	Depreciation and depletion expense		$	63,614	$	70,205
Amortization expense	Amortization expense	4,630		4,928		12,972		14,029		Amortization expense		2,672		4,152
Amortization of CO2 volumetric production payments		—		162		—		890
Total depreciation, depletion and amortization expense	Total depreciation, depletion and amortization expense	$	67,733	$	83,522	$	222,210	$	240,513	Total depreciation, depletion and amortization expense		$	66,286	$	74,357

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~March 31, 2020

Total depreciation, depletion, and amortization expense for the ~~2020~~2021 Quarter decreased by ~~$15.8 million. This decrease is primarily~~$8.1 million due to lower depreciation expense ~~in the 2020 Quarter~~ associated with our rail logistics assets in the 2021 Quarter as they were impaired during the second quarter of 2020. Additionally, ~~the 2019 Quarter included an increase in depreciation charges~~our contract intangible associated with ~~one of our non-core gas offshore assets in which~~ the ~~abandonment timing was accelerated.~~

~~Nine Months Ended~~M/T American Phoenix became fully amortized on September 30, 2020, ~~Compared with Nine Months Ended September 30, 2019~~

~~Total depreciation, depletion, and~~which resulted in lower amortization expense for the nine months ended September 30, 2020 decreased $18.3 million. This decrease is primarily due to lower depreciation expense in 2020 associated with our rail logistics assets as they were impaired during the second quarter of 2020. Additionally, the nine months ended September 30, 2019 included an increase in depreciation charges associated with one of our non-core gas offshore assets in which the abandonment timing was accelerated and higher overall amortization expense.

~~Table of Contents~~

~~Impairment Expense~~

As previously discussed, during the nine months ended September 30, 2020, we recorded impairment expense of approximately $277 million associated with the rail logistics assets included within our onshore facilities and transportation segment. We also recorded approximately $3 million of impairment expense in the ~~2020 Quarter associated with the full write-off of one of our non-core offshore gas platforms which does not have a future use with our operations.~~2021 Quarter.

Interest expense, net


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019		2020		2019				2021		2020
		(in thousands)				(in thousands)					(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	Interest expense, senior secured credit facility (including commitment fees)	$	9,415	$	13,572	$	29,824	$	42,034	Interest expense, senior secured credit facility (including commitment fees)		$	7,431	$	10,745
Interest expense, senior unsecured notes	Interest expense, senior unsecured notes	39,842		39,547		122,402		118,641		Interest expense, senior unsecured notes		48,335		42,358
Amortization of debt issuance costs and discount	Amortization of debt issuance costs and discount	2,454		2,695		7,045		8,065		Amortization of debt issuance costs and discount		2,715		2,391
Capitalized interest	Capitalized interest	(399)		(1,141)		(1,376)		(2,859)		Capitalized interest		(652)		(529)
Net interest expense	Net interest expense	$	51,312	$	54,673	$	157,895	$	165,881	Net interest expense		$	57,829	$	54,965

Three Months Ended ~~September 30, 2020~~March 31, 2021 Compared with Three Months Ended ~~September 30, 2019~~March 31, 2020

Net interest expense for the ~~2020~~2021 Quarter ~~decreased $3.4~~increased by $2.9 million primarily due to a lower interest rate on our revolving credit facility during the period. The decline in our interest rate during the 2020 Quarter is due to the decrease in LIBOR rates during the 2020 Quarter, which is one of the main drivers ofincreased interest expense ~~on our credit facility. Additionally, we have repurchased a total of $97.6 million of~~associated with our senior unsecured ~~notes on the open market during 2020 for a gain of $20.5 million, which reduced our overall outstanding indebtedness and interest expense during the period.~~

~~These decreases were partially offset by higher interest expense on our senior unsecured notes and lower capitalized interest during the 2020 Quarter.~~notes. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75%, and we purchased and extinguished ~~$527.9 million of~~ our $750 million 2022 Notes that accrued interest at 6.75% ~~on January 15,~~during the 2020 ~~through~~Quarter. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest at 8.00%. We used the net proceeds to repay a ~~tender offer~~portion of our 6% 2023 Notes that were validly tendered and we redeemed the remaining ~~$222.1~~principal balance of $80.9 million on our 6% 2023 Notes on January 19, 2021. The excess proceeds received from the issuance of our ~~2022~~2027 Notes were used to repay borrowings on ~~February 16, 2020.~~our revolving credit facility.

~~Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019~~

~~Net~~The increase in interest expense ~~for the nine months ended September 30, 2020 decreased~~on our senior unsecured notes was partially offset by ~~$8.0 million~~lower interest expense on our senior secured credit facility. The decrease in interest expense on our senior secured credit facility was primarily due to a lower ~~interest rate on our revolving credit facility during the period. The decline in our~~outstanding balance and a lower interest rate during ~~2020 is due to~~ the ~~decrease in~~2021 Quarter. Interest rates on our senior secured credit facility decreased as a result of lower LIBOR rates during the ~~period,~~2021 Quarter relative to the 2020 Quarter, which is one of the main drivers of interest expense on our credit facility. Additionally, we repurchased a total of $97.6 million of our senior unsecured notes on the open market during 2020 for a gain of $20.5 million, which reduced our overall outstanding indebtedness and interest expense during the year.

These decreases were partially offset by higher interest expense on our senior unsecured notes and lower capitalized interest during the 2020 Quarter. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75%, and we purchased and extinguished $527.9 million of our $750 million 2022 Notes that accrued interest at 6.75% on January 15, 2020 through a tender offer and we redeemed the remaining $222.1 million of our 2022 Notes on February 16, 2020.

Income tax expense

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

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Liquidity and Capital Resources

General

As of ~~September 30, 2020,~~March 31, 2021, our balance sheet and liquidity position remained strong, ~~including $714.1~~which included $999.7 million of remaining borrowing capacity under our $1.7 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our new credit ~~facility~~agreement discussed below will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our prior credit facility and the proceeds from issuances of equity and senior unsecured notes.

Our primary cash requirements consist of:

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

•routine operating expenses;

•capital growth and maintenance projects;

•acquisitions of assets or businesses;

•payments related to servicing and reducing outstanding debt; and

•quarterly cash distributions to our preferred and common unitholders.

On April 8, 2021, we entered into the new credit agreement to replace our existing agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprising a term loan facility of $300 million and a revolving loan facility of $650 million, with the ability to increase the aggregate size of the revolving loan facility by an additional $200 million subject to lender consent and certain other customary conditions. The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions. The successful completion of our new credit agreement has resulted in no scheduled maturities of long-term debt until 2024, other than the minimal quarterly payments due under the associated term loan facility each quarter beginning at the end of 2021 (which will be funded by the available capacity under our revolving loan facility).

Furthermore, on April 22, 2021 we completed our offering of an additional $250 million in aggregate principal amount of our 2027 Notes. The notes constitute an additional issuance of our existing 2027 Notes that we issued on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms as (other than with respect to issue price) and constitute part of the same series of the 2027 Notes we issued on December 17, 2020. The $250 million of the 2027 Notes were issued at a premium of 103.75%, plus accrued interest from December 17, 2020. We intend to use the net proceeds from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our new credit facility. As a result of this issuance, we have been able to increase the available borrowing capacity on our new credit agreement, which provides us additional liquidity to comfortably satisfy our primary cash requirements discussed above.

Capital Resources

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

At ~~September 30, 2020,~~March 31, 2021, our long-term debt totaled approximately ~~$3,358.7~~$3,370.3 million, which is a reduction of ~~$73.9~~$23.5 million sequentially from ~~June 30,~~December 31, 2020, and ~~consists~~consisted of ~~$984.8~~$699.0 million outstanding under our prior credit facility (including ~~$27.8~~$13.0 million borrowed under the inventory sublimit tranche) and ~~$2,374~~$2,671.3 million of senior unsecured notes, net of issuance costs, comprising ~~$396.2 million carrying amount due on May 15, 2023, $338.0~~of $338.4 million carrying amount due on June 15, 2024, ~~$528.9~~$529.5 million carrying amount due October 2025, ~~$395.8~~$355.8 million carrying ~~amount~~value due May 2026, $737.5 million carrying value due January 15, 2027, and ~~$715.1~~$710.1 million carrying amount due February 15, 2028. Given the market conditions during 2020, we continued to take the opportunity to repurchase certain of our senior unsecured notes. As of September 30, 2020, we have repurchased approximately $97.5 million of our senior unsecured notes on the open market in exchange for $77.0 million, which was borrowed under our credit facility, and reduced our total indebtedness by $20.5 million. We remain focused on continuing to be a net payer of debt and reducing our operating leverage.

On September 23, 2019, we announced the ~~expansion of our existing~~ Granger ~~facility (the "Granger~~ Optimization ~~Project" or "GOP").~~Project. We entered into agreements with GSO for the purchase of up to approximately $350 million of preferred units of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. The extended completion date of the project is anticipated in late 2023. The Alkali Holdings preferred unitholders ~~will~~ receive PIK distributions in lieu of cash distributions during the new anticipated construction period. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.

~~Equity Distribution Program and~~

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Shelf Registration ~~Statements~~Statement

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

In 2016, we implemented an equity distribution program that allowed us to consummate “at the market” offerings of common units from time to time through brokered transactions. In connection with implementing our equity distribution program, we filedWe have a universal shelf registration statement (our ~~"EDP Shelf") with the SEC. Our EDP Shelf expired in October 2020 and we have no plans to file a replacement EDP Shelf. We did not issue any units under this program.~~

~~We have another universal shelf registration statement (our "2018~~"2021 Shelf") on file with the ~~SEC.~~SEC which we filed on April 19, 2021 to replace our existing universal shelf registration statement that expired on April 20, 2021. Our ~~2018~~2021 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our ~~2018 Shelf will~~2021Shelf is set to expire in April ~~2021. We expect to file a replacement universal shelf registration statement before our 2018 Shelf expires.~~

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2024.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our capital expenditures and asset retirement obligations (if any). Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

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

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

In our Alkali Business, we typically extract trona from our mining facilities, process it into soda ash and other alkali products, and deliver and sell the alkali products to our customers all within a relatively short time frame. If we do experience any differences in timing of extraction, processing and sales of our trona or alkali products, it could impact the cash requirements for these activities in the short term.

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

See Note 14 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the ~~nine months ended September 30,~~2021 Quarter and 2020 ~~and September 30, 2019.~~Quarter.

Net cash flows provided by our operating activities for the ~~nine months ended September 30, 2020~~2021 Quarter were ~~$295.6~~$77.2 million compared to ~~$331.7~~$89.6 million for the ~~nine months ended September 30, 2019.~~2020 Quarter. This decrease is primarily attributable to lower ~~segment margin and transactions costs incurred~~Segment Margin during ~~2020 associated with~~ the ~~tender and redemption of our previously held 2022 Notes, partially offset by positive changes in working capital.~~2021 Quarter.

Capital Expenditures, Distributions and Certain Cash Requirements

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

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Capital Expenditures

A summary of our expenditures for fixed assets, business and other asset acquisitions for the ~~nine months ended September 30,~~2021 Quarter and 2020 ~~and September 30, 2019 is~~Quarter are as follows:


		Nine Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
		(in thousands)					(in thousands)
Capital expenditures for fixed and intangible assets:	Capital expenditures for fixed and intangible assets:					Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:	Maintenance capital expenditures:					Maintenance capital expenditures:
Offshore pipeline transportation assets	Offshore pipeline transportation assets	$	3,641	$	4,870	Offshore pipeline transportation assets	$	5,817	$	768
Sodium minerals and sulfur services assets	Sodium minerals and sulfur services assets	23,647		32,653		Sodium minerals and sulfur services assets	7,639		4,575
Marine transportation assets	Marine transportation assets	22,998		29,665		Marine transportation assets	11,714		14,232
Onshore facilities and transportation assets	Onshore facilities and transportation assets	2,988		1,989		Onshore facilities and transportation assets	980		908
Information technology systems	Information technology systems	213		909		Information technology systems	3		75
Total maintenance capital expenditures	Total maintenance capital expenditures	53,487		70,086		Total maintenance capital expenditures	26,153		20,558
Growth capital expenditures:	Growth capital expenditures:					Growth capital expenditures:
Offshore pipeline transportation assets	Offshore pipeline transportation assets	2,268		105		Offshore pipeline transportation assets	5,711		259
Sodium minerals and sulfur services assets	Sodium minerals and sulfur services assets	44,015		42,605		Sodium minerals and sulfur services assets	2,399		10,400
Marine transportation assets	Marine transportation assets	—		—		Marine transportation assets	—		—
Onshore facilities and transportation assets	Onshore facilities and transportation assets	444		3,394		Onshore facilities and transportation assets	119		249
Information technology systems	Information technology systems	4,175		1,798		Information technology systems	1,653		1,178
Total growth capital expenditures	Total growth capital expenditures	50,902		47,902		Total growth capital expenditures	9,882		12,086
Total capital expenditures		$	104,389	$	117,988
Total capital expenditures for fixed and intangible assets						Total capital expenditures for fixed and intangible assets	$	36,035	$	32,644

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We continue to pursue a long-term growth strategy that may require significant capital.

Growth Capital Expenditures

On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with GSO for the purchase of up to approximately $350 million of preferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. The extended completion date of the project is anticipated in late 2023. We issued 1,750 preferred units to GSO in consideration for the amendment. The Alkali Holdings preferred unitholders ~~will~~ receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of ~~September 30, 2020~~March 31, 2021 we had issued ~~139,359~~161,209 Alkali Holdings preferred units. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.

Except for the Granger Optimization Project, we do not anticipate spending material growth capital expenditures on any individual projects during the rest of ~~2020.~~2021.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred during ~~2020~~2021 primarily relate to expenditures in our Alkali Business, our marine transportation segment, and in our ~~marine~~offshore transportation segment. Our Alkali Business, which is included in our sodium minerals and sulfur services segment, incurs expenditures to maintain its equipment and facilities due to the nature of its operations. Our marine transportation segment incurs expenditures as we frequently replace and upgrade certain equipment associated with our barge and vessel fleet during our planned and unplanned ~~drydocks.~~dry-docks. Additionally, we incurred maintenance capital expenditures in our offshore transportation segment to replace certain pipeline and platform equipment and complete the installation of a bypass to allow our CHOPS pipeline to resume operations in the 2021 Quarter. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.

Distributions to Unitholders

On ~~November 13, 2020,~~May 14, 2021, we will pay a distribution of $0.15 per common unit totaling $18.4 million with respect to the ~~2020~~2021 Quarter. Information on our recent distribution history is included in Note 10 to our Unaudited Condensed Consolidated Financial Statements.

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With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.7374 per Class A Convertible Preferred Unit (or $2.9496 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on ~~November 13, 2020~~May 14, 2021 to unitholders of record at the close of business on ~~October~~April 30, ~~2020.~~2021.

Guarantor Summarized Financial Information

Our ~~$2.4~~$2.7 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries (the "Guarantor Subsidiaries), except the subsidiaries that hold our Alkali Business (collectively, the "Alkali Subsidiaries"), Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and certain other subsidiaries. The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020 and the ownership of Genesis NEJD Pipeline LLC's pipeline was transferred on October, 2020. 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. The Guarantor Subsidiaries largely own the assets that we use to operate our business other than our Alkali Business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Alkali Holdings and Genesis Energy, L.P., to the extent agreed to in the Services Agreement. Genesis Energy Finance Corporation has no independent assets or operations. See Note 9 for additional information regarding our consolidated debt obligations.

The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes, the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution of such Guarantor Subsidiary (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.

The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.

The following is the summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a combined basis after elimination of intercompany transactions, which includes related receivable and payable balances, and the investment in and equity earnings from the Non-Guarantor Subsidiaries.


Balance Sheets	Balance Sheets	Genesis Energy, L.P. and Guarantor Subsidiaries				Balance Sheets	Genesis Energy, L.P. and Guarantor Subsidiaries
		September 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
ASSETS:	ASSETS:					ASSETS:
Current assets	Current assets	$	246,540	$	323,492	Current assets	$	383,742	$	313,328
Fixed assets, net	Fixed assets, net	3,143,374		3,538,450		Fixed assets, net	3,096,330		3,115,492
Non-current assets	Non-current assets	876,996		951,276		Non-current assets	843,824		861,230

LIABILITIES AND CAPITAL:(1)	LIABILITIES AND CAPITAL:(1)					LIABILITIES AND CAPITAL:(1)
Current liabilities	Current liabilities	223,939		292,941		Current liabilities	354,508		266,688
Non-current liabilities	Non-current liabilities	3,654,873		3,738,816		Non-current liabilities	3,706,448		3,710,044
Class A Convertible Preferred Units	Class A Convertible Preferred Units	790,115		790,115		Class A Convertible Preferred Units	790,115		790,115

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Statements of Operations	Statements of Operations	Genesis Energy, L.P. and Guarantor Subsidiaries				Statements of Operations	Genesis Energy, L.P. and Guarantor Subsidiaries
		Nine Months Ended September 30, 2020		Twelve Months Ended December 31. 2019			Three Months Ended March 31, 2021		Twelve Months Ended December 31. 2020
Revenues	Revenues	$	882,751	$	1,617,170	Revenues	$	351,527	$	1,156,428
Operating costs	Operating costs	1,104,748		1,454,040		Operating costs	335,149		1,421,674
Operating income (loss)	Operating income (loss)	(221,997)		163,130		Operating income (loss)	16,379		(265,246)
Income (loss) before income taxes		(316,653)		566
Loss before income taxes						Loss before income taxes	(40,856)		(408,717)
Net loss(1)	Net loss(1)	(317,227)		(122)		Net loss(1)	(41,077)		(409,951)

Less: Accumulated distributions to Class A Convertible Preferred Units	Less: Accumulated distributions to Class A Convertible Preferred Units	(56,052)		(74,467)		Less: Accumulated distributions to Class A Convertible Preferred Units	(74,736)		(74,736)
Net loss available to common unitholders	Net loss available to common unitholders	(373,279)		(74,589)		Net loss available to common unitholders	(115,813)		(484,687)

(1) There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for either period presented.

Excluded from non-current assets in the table above are ~~$29.9~~$80.1 million and ~~$76.2~~$95.7 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the Non-Guarantor Subsidiaries as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively.

Non-GAAP Financial Measure Reconciliations

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

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


		Three Months Ended September 30,					Three Months Ended March 31,
		2020		2019			2021		2020
		(in thousands)					(in thousands)
Net income (loss) attributable to Genesis Energy, L.P.	Net income (loss) attributable to Genesis Energy, L.P.	$	(29,717)	$	17,557	Net income (loss) attributable to Genesis Energy, L.P.	$	(34,224)	$	24,909
Income tax expense		145		111
Income tax expense (benefit)						Income tax expense (benefit)	222		(365)
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	70,203		87,209		Depreciation, depletion, amortization and accretion	68,997		75,978
Impairment expense		3,331		—

Plus (minus) Select Items, net	Plus (minus) Select Items, net	52,091		2,990		Plus (minus) Select Items, net	46,495		4,806
Maintenance capital utilized (1)	Maintenance capital utilized (1)	(10,600)		(6,825)		Maintenance capital utilized (1)	(12,850)		(8,800)
Cash tax expense	Cash tax expense	(250)		(149)		Cash tax expense	(150)		(150)
Distributions to preferred unitholders	Distributions to preferred unitholders	(18,684)		(18,684)		Distributions to preferred unitholders	(18,684)		(18,684)
Redeemable noncontrolling interest redemption value adjustments (2)	Redeemable noncontrolling interest redemption value adjustments (2)	4,149		272		Redeemable noncontrolling interest redemption value adjustments (2)	4,791		4,086

Available Cash before Reserves	Available Cash before Reserves	$	70,668	$	82,481	Available Cash before Reserves	$	54,597	$	81,780

(1)For a description of the term "maintenance capital utilized", please see the definition of the term "Available Cash before Reserves" discussed below. Maintenance capital expenditures in the 2021 Quarter and 2020 Quarter ~~and 2019 Quarter~~ were ~~$19.9~~$26.2 million and ~~$26.8~~$20.6 million, respectively.

(2)Includes PIK distributions attributable to the period and accretion on the redemption feature.

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

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			Three Months Ended September 30,						Three Months Ended March 31,
			2020		2019				2021		2020
			(in thousands)						(in thousands)
I.	I.	Applicable to all Non-GAAP Measures					I.	Applicable to all Non-GAAP Measures
		Differences in timing of cash receipts for certain contractual arrangements (1)	$	13,052	$	1,249		Differences in timing of cash receipts for certain contractual arrangements (1)	$	299	$	4,490
		Adjustment regarding direct financing leases (2)	44,088		2,131			Distribution from unrestricted subsidiaries not included in income (2)	17,500		2,238

		Certain non-cash items:						Certain non-cash items:
		Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value (3)	(9,772)		(10,398)			Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value (3)	17,687		(31,002)
								Loss on debt extinguishment (4)	1,627		23,480
		Adjustment regarding equity investees (4)	2,318		7,682			Adjustment regarding equity investees (5)	8,856		6,406
		Other	2,060		518			Other	757		(2,259)
		Sub-total Select Items, net (5)	51,746		1,182			Sub-total Select Items, net	46,726		3,353
II.	II.	Applicable only to Available Cash before Reserves					II.	Applicable only to Available Cash before Reserves
		Certain transaction costs (6)	55		2,964			Certain transaction costs (6)	114		—

		Other	290		(1,156)			Other	(345)		1,453
		Total Select Items, net (7)	$	52,091	$	2,990		Total Select Items, net (7)	$	46,495	$	4,806

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

(2) ~~Represents the net effect of adding~~The 2021 Quarter includes $17.5 million in cash receipts ~~from direct financing leases and deducting expenses relating to direct financing leases.~~associated with principal repayments on our previously owned NEJD pipeline not included in income. The 2020 Quarter includes cash payments received from the ~~cash we received associated with the exercise~~NEJD pipeline of ~~a letter of credit we had issued to us~~$2.2 million not included in income. Genesis NEJD Pipeline, LLC is defined as ~~beneficiary from a customer that defaulted~~an unrestricted subsidiary under our ~~agreement.~~credit facility.

(3) The ~~2020~~2021 Quarter includes a ~~$6.7~~$18.4 million unrealized ~~gain~~loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and the ~~2019~~2020 Quarter includes a ~~$8.0~~$32.5 million unrealized gain from the valuation of the embedded derivative.

(4) The 2021 Quarter includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining 2023 Notes. The 2020 Quarter includes the transaction costs associated with the tender and redemption of our 2022 Notes, along with the write-off of the unamortized issuance costs and discount associated with these notes.

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

~~(5) Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.~~

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

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

Non-GAAP Financial Measures

General

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

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other

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market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user. Our non-GAAP financial measures should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

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Segment Margin

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results.

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

Available Cash before Reserves

Purposes, Uses and Definition

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

(1) the financial performance of our assets;

(2) our operating performance;

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

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

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

Disclosure Format Relating to Maintenance Capital

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

Maintenance Capital Requirements

Maintenance Capital Expenditures

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

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

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

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of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

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

Maintenance Capital Utilized

We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.

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

Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Commercial Commitments

There have been no material changes to the commitments and obligations reflected in our Annual Report.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report, nor do we have any debt or equity triggers based upon our unit or commodity prices.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, estimated or projected future financial performance, our expectations regarding the potential impact of the Covid-19 pandemic, the impact of our cost saving measures and the amount of such cost savings, and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:

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•demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, soda ash, and caustic soda, ~~and CO~~2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, pandemics (including Covid-19), the actions of OPEC and other oil exporting nations, conservation and technological advances;

•our ability to successfully execute our business and financial strategies;

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•our ability to realize cost savings from our recent cost saving measures;

•the realized benefits of the preferred equity investment in Alkali Holdings by GSO or our ability to comply with the GOP agreements and maintain control over and ownership of the Alkali Business;

•throughput levels and rates;

•changes in, or challenges to, our tariff rates;

•our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

•service interruptions in our pipeline transportation systems, processing operations, or mining facilities;

•shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants, or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell soda ash, petroleum, or other products;

•risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

•changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;

•the effects of production declines resulting from a suspension of drilling in the Gulf of Mexico or otherwise;

•the effects of future laws and regulations;

•planned capital expenditures and availability of capital resources to fund capital expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;

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

•loss of key personnel;

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

•an increase in the competition that our operations encounter;

•cost and availability of insurance;

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

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

•changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;

•the impact of natural disasters, pandemics (including Covid-19), epidemics, accidents or terrorism, and actions taken by governmental authorities and other third parties in response thereto, on our business financial condition and results of operations;

•reduction in demand for our services resulting in impairments of our assets;

•changes in the financial condition of customers or counterparties;

•adverse rulings, judgments, or settlements in litigation or other legal or tax matters;

•the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes;

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•the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price; and

•a cyberattack involving our information systems and related infrastructure, or that of our business associates.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report . These risks may also

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be specifically described in our Quarterly Reports on Form 10-Q, ~~and~~ Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Item 4. Controls and Procedures

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

There were no changes during the ~~2020~~2021 Quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~2020. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

There has been no material change in our risk factors as previously disclosed in our Annual Report ~~and Quarterly Report~~ on Form ~~10-Q~~10-K for the ~~quarter~~fiscal year ended ~~June 30,~~December 31, 2020.

For additional information about our risk factors, see Item 1A of our Annual Report, ~~and Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020,~~ as well as any other risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

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

There were no sales of unregistered equity securities during the ~~2020~~2021 Quarter.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

None.

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Item 6. Exhibits.

(a) Exhibits


	3.1	Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 of the Registration Statement on Form S-1, File No. 333-11545).
	3.2	Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).
	3.3	Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 5.1 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4	First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated September 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 7, 2017, File No. 001-12295).
	3.5	Second Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated December 31, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated January 4, 2018, File No. 001-12295).
	3.6	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.7	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.8	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 5.2 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.9	Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006 (incorporated by reference to Exhibit 3.7 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	3.10	Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
*	10.1	Fifth Amended and Restated Credit Agreement, dated as of April 8, 2021, among Genesis Energy, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A., as syndication agent, and the lenders party thereto.
*	22.1	List of Issuers and Guarantor Subsidiaries ~~(incorporated by reference to Exhibit 22.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, File No. 001-12295).~~
*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	95	Mine Safety Disclosures.
	101.INS	XBRL Instance Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
	101.SCH	XBRL Schema Document.
	101.CAL	XBRL Calculation Linkbase Document.
	101.LAB	XBRL Label Linkbase Document.
	101.PRE	XBRL Presentation Linkbase Document.
	101.DEF	XBRL Definition Linkbase Document.
	104	Cover Page Interactive Data File (formatted as Inline XBRL).


*			Filed herewith

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SIGNATURES

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


						GENESIS ENERGY, L.P. (A Delaware Limited Partnership)

			By:			GENESIS ENERGY, LLC, as General Partner


Date:	~~November~~May 5, ~~2020~~2021	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer
			(Duly Authorized Officer)

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	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total
Partners’ capital, June 30, 2020	122,579	$	1,018,342	$	(1,900)	$	(8,188)	$	1,008,254
Net loss	—	(29,717)		(12)		—		(29,729)
Cash distributions to partners	—	(18,387)		—		—		(18,387)
Cash contributions from noncontrolling interests	—	—		319		—		319
Other comprehensive income	—	—		—		122		122
Distributions to Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)


Partners' capital, September 30, 2020	122,579	$	951,554	$	(1,593)	$	(8,066)	$	941,895
	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Income		Total
Partners’ capital, June 30, 2019	122,579	$	1,575,599	$	(8,449)	$	939	$	1,568,089
Net income	—	17,557		(22)		—		17,535
Cash distributions to partners	—	(67,418)		—		—		(67,418)
Cash contributions from noncontrolling interests	—	—		2,375		—		2,375
Distributions to Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)
Partners' capital, September 30, 2019	122,579	$	1,507,054	$	(6,096)	$	939	$	1,501,897


	Three Months Ended September 30, 2019
	Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	79,738	$	0	$	59,404	$	36,937	$	176,079
Product Sales	0		259,332		0		168,091		427,423
Refinery Services	0		18,195		0		0		18,195
	$	79,738	$	277,527	$	59,404	$	205,028	$	621,697


Maturity of Lessor Receipts	Onshore Facilities and Transportation
Remainder of 2020	$	300
2021	1,200
2022	1,200
2023	1,200
2024	1,200
Thereafter	4,100
Total Lease Receipts	$	9,200


Remainder of	2020	$	2,619
	2021	$	9,493
	2022	$	9,513
	2023	$	10,183
	2024	$	10,900


Remainder of	2020	$	2,781
	2021	$	10,729
	2022	$	10,571
	2023	$	10,303
	2024	$	9,988


Distribution For	Date Issued	Number of Units (1)	Total Amount







2019
1st Quarter	May 15, 2019	364,180	$	12,277