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 June 30, ~~2022~~2023

☐ 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,~~811 Louisiana, Suite ~~2100,~~1200,

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 ~~July 29, 2022.~~August 2, 2023.

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GENESIS ENERGY, L.P.

TABLE OF CONTENTS


		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets as of June 3 0 , ~~2022~~2023 (unaudited) and December 31, ~~2021~~2022	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Comprehensive ~~Income (Loss)~~Incom e	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	8
	3. Revenue Recognition	9
	4. ~~Lease Accounting~~Business Consolidation	10
	5. ~~Inventories~~Lease Accounting	1112
	6. Inventories	13
	7. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations	12
	~~7. Equity Investees~~	1314
	8. ~~Intangible Assets~~	14
	~~9. Debt~~Equity Investees	15
	9. Intangible Assets	16
	10. ~~Partners~~’ ~~Capital, Mezzanine Capital and Distributions~~Debt	17
	11. ~~Net~~ ~~Income~~(~~Loss~~) ~~Per Common Unit~~Partners’ Capital, Mezzanine Capital and Distributions	1918
	12. ~~Business Segment Information~~Net Income Per Common Unit	2021
	13. ~~Transactions with Related Parties~~Business Segment Information	2322
	14. ~~Supplemental Cash Flow Information~~Transactions with Related Parties	2425
	15. ~~Derivatives~~Supplemental Cash Flow Information	2425
	16. ~~Fair-Value Measurements~~Derivatives	2826
	17. Fair-Value Measurements	30
	18. Commitments and Contingencies	2931

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3032
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5456
Item 4.	Controls and Procedures	5456
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	5557
Item 1A.	Risk Factors	5557
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5557
Item 3.	Defaults upon Senior Securities	5557
Item 4.	Mine Safety Disclosures	5557
Item 5.	Other Information	5557
Item 6.	Exhibits	5658
SIGNATURES		5759

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)


		June 30, 2022		December 31, 2021			June 30, 2023		December 31, 2022
		(unaudited)					(unaudited)
ASSETS	ASSETS					ASSETS
CURRENT ASSETS:	CURRENT ASSETS:					CURRENT ASSETS:
Cash and cash equivalents	Cash and cash equivalents	$	10,070	$	19,987	Cash and cash equivalents	$	11,506	$	7,930
Restricted cash	Restricted cash	18,446		5,005		Restricted cash	18,804		18,637
Accounts receivable - trade, net	Accounts receivable - trade, net	453,502		400,334		Accounts receivable - trade, net	774,086		721,567
Inventories	Inventories	91,834		77,958		Inventories	117,852		78,143

Other	Other	31,239		39,200		Other	43,446		26,770
Total current assets	Total current assets	605,091		542,484		Total current assets	965,694		853,047
FIXED ASSETS, at cost	FIXED ASSETS, at cost	5,599,512		5,464,040		FIXED ASSETS, at cost	6,059,542		5,865,038
Less: Accumulated depreciation	Less: Accumulated depreciation	(1,661,837)		(1,551,855)		Less: Accumulated depreciation	(1,875,840)		(1,768,465)
Net fixed assets	Net fixed assets	3,937,675		3,912,185		Net fixed assets	4,183,702		4,096,573
MINERAL LEASEHOLDS, net of accumulated depletion	MINERAL LEASEHOLDS, net of accumulated depletion	547,071		549,005		MINERAL LEASEHOLDS, net of accumulated depletion	542,973		545,122

EQUITY INVESTEES	EQUITY INVESTEES	287,748		294,050		EQUITY INVESTEES	274,233		284,486
INTANGIBLE ASSETS, net of amortization	INTANGIBLE ASSETS, net of amortization	126,700		127,063		INTANGIBLE ASSETS, net of amortization	138,280		127,320
GOODWILL	GOODWILL	301,959		301,959		GOODWILL	301,959		301,959
RIGHT OF USE ASSETS, net	RIGHT OF USE ASSETS, net	133,476		140,796		RIGHT OF USE ASSETS, net	223,179		125,277
OTHER ASSETS, net of amortization	OTHER ASSETS, net of amortization	31,740		38,259		OTHER ASSETS, net of amortization	39,439		32,208
TOTAL ASSETS	TOTAL ASSETS	$	5,971,460	$	5,905,801	TOTAL ASSETS	$	6,669,459	$	6,365,992
LIABILITIES AND CAPITAL	LIABILITIES AND CAPITAL					LIABILITIES AND CAPITAL
CURRENT LIABILITIES:	CURRENT LIABILITIES:					CURRENT LIABILITIES:
Accounts payable - trade	Accounts payable - trade	$	256,086	$	264,316	Accounts payable - trade	$	524,268	$	427,961
Accrued liabilities	Accrued liabilities	253,369		232,623		Accrued liabilities	333,712		281,146

Total current liabilities	Total current liabilities	509,455		496,939		Total current liabilities	857,980		709,107
SENIOR SECURED CREDIT FACILITY	SENIOR SECURED CREDIT FACILITY	34,600		49,000		SENIOR SECURED CREDIT FACILITY	133,600		205,400
SENIOR UNSECURED NOTES, net of debt issuance costs and premium	SENIOR UNSECURED NOTES, net of debt issuance costs and premium	2,888,422		2,930,505		SENIOR UNSECURED NOTES, net of debt issuance costs and premium	3,009,850		2,856,312
ALKALI SENIOR SECURED NOTES, net of debt issuance costs and discount	ALKALI SENIOR SECURED NOTES, net of debt issuance costs and discount	402,204		—		ALKALI SENIOR SECURED NOTES, net of debt issuance costs and discount	397,008		402,442
DEFERRED TAX LIABILITIES	DEFERRED TAX LIABILITIES	14,897		14,297		DEFERRED TAX LIABILITIES	17,203		16,652
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES	441,226		434,925		OTHER LONG-TERM LIABILITIES	516,143		400,617
Total liabilities	Total liabilities	4,290,804		3,925,666		Total liabilities	4,931,784		4,590,530

MEZZANINE CAPITAL:	MEZZANINE CAPITAL:					MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at June 30, 2022 and December 31, 2021		790,115		790,115
Redeemable noncontrolling interests, 0 units issued and outstanding at June 30, 2022 and 246,394 preferred units issued and outstanding December 31, 2021		—		259,568
Class A Convertible Preferred Units, 24,595,158 and 25,336,778 issued and outstanding at June 30, 2023 and December 31, 2022, respectively.						Class A Convertible Preferred Units, 24,595,158 and 25,336,778 issued and outstanding at June 30, 2023 and December 31, 2022, respectively.	865,802		891,909

PARTNERS’ CAPITAL:	PARTNERS’ CAPITAL:					PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 units issued and outstanding at June 30, 2022 and December 31, 2021		596,059		641,313
Accumulated other comprehensive loss		(5,364)		(5,607)
Common unitholders, 122,579,218 units issued and outstanding at June 30, 2023 and December 31, 2022						Common unitholders, 122,579,218 units issued and outstanding at June 30, 2023 and December 31, 2022	531,291		567,277
Accumulated other comprehensive income						Accumulated other comprehensive income	6,357		6,114
Noncontrolling interests	Noncontrolling interests	299,846		294,746		Noncontrolling interests	334,225		310,162
Total partners’ capital	Total partners’ capital	890,541		930,452		Total partners’ capital	871,873		883,553
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	5,971,460	$	5,905,801	TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	6,669,459	$	6,365,992

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)


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022			2023		2022
REVENUES:	REVENUES:									REVENUES:
Offshore pipeline transportation	Offshore pipeline transportation	$	82,085	$	73,221	$	150,153	$	137,605	Offshore pipeline transportation	$	91,459	$	82,085		$	182,854	$	150,153
Sodium minerals and sulfur services		318,608		237,087		604,282		464,374
Soda and sulfur services										Soda and sulfur services	462,855		318,608			907,503		604,282
Marine transportation	Marine transportation	76,320		47,626		132,094		87,957		Marine transportation	77,343		76,320			160,569		132,094
Onshore facilities and transportation	Onshore facilities and transportation	244,712		145,921		467,143		335,138		Onshore facilities and transportation	173,005		244,712			344,348		467,143
Total revenues	Total revenues	721,725		503,855		1,353,672		1,025,074		Total revenues	804,662		721,725			1,595,274		1,353,672
COSTS AND EXPENSES:	COSTS AND EXPENSES:									COSTS AND EXPENSES:
Onshore facilities and transportation product costs	Onshore facilities and transportation product costs	217,703		124,684		417,305		285,435		Onshore facilities and transportation product costs	149,429		217,703			298,485		417,305
Onshore facilities and transportation operating costs	Onshore facilities and transportation operating costs	16,902		15,833		32,579		32,095		Onshore facilities and transportation operating costs	17,839		16,902			35,219		32,579
Marine transportation operating costs	Marine transportation operating costs	58,924		39,118		102,652		72,204		Marine transportation operating costs	51,848		58,924			109,584		102,652
Sodium minerals and sulfur services operating costs		250,914		196,971		464,539		381,402
Soda and sulfur services operating costs										Soda and sulfur services operating costs	372,665		250,914			778,887		464,539
Offshore pipeline transportation operating costs	Offshore pipeline transportation operating costs	26,359		21,264		49,375		41,980		Offshore pipeline transportation operating costs	24,739		26,359			47,864		49,375
General and administrative	General and administrative	20,665		12,907		35,787		24,573		General and administrative	16,931		20,665			31,483		35,787
Depreciation, depletion and amortization	Depreciation, depletion and amortization	73,673		67,541		143,179		133,827		Depreciation, depletion and amortization	68,427		73,673			141,587		143,179
Gain on sale of asset	Gain on sale of asset	(40,000)		—		(40,000)		—		Gain on sale of asset	—		(40,000)			—		(40,000)

Total costs and expenses	Total costs and expenses	625,140		478,318		1,205,416		971,516		Total costs and expenses	701,878		625,140			1,443,109		1,205,416
OPERATING INCOME	OPERATING INCOME	96,585		25,537		148,256		53,558		OPERATING INCOME	102,784		96,585			152,165		148,256
Equity in earnings of equity investees	Equity in earnings of equity investees	14,572		14,222		27,016		34,882		Equity in earnings of equity investees	14,811		14,572			32,364		27,016
Interest expense	Interest expense	(55,959)		(59,169)		(111,063)		(116,998)		Interest expense	(61,623)		(55,959)			(122,477)		(111,063)
Other income (expense)	Other income (expense)	14,888		(15,845)		10,630		(35,910)		Other income (expense)	(4)		14,888			(1,812)		10,630
Income (loss) from operations before income taxes		70,086		(35,255)		74,839		(64,468)
Income from operations before income taxes										Income from operations before income taxes	55,968		70,086		—	60,240		74,839
Income tax expense	Income tax expense	(571)		(525)		(875)		(747)		Income tax expense	(290)		(571)			(1,174)		(875)

NET INCOME (LOSS)		69,515		(35,780)		73,964		(65,215)
NET INCOME										NET INCOME	55,678		69,515			59,066		73,964
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(11,548)		(136)		(13,424)		(134)		Net income attributable to noncontrolling interests	(6,334)		(11,548)			(11,366)		(13,424)
Net income attributable to redeemable noncontrolling interests	Net income attributable to redeemable noncontrolling interests	(22,620)		(5,766)		(30,443)		(10,557)		Net income attributable to redeemable noncontrolling interests	—		(22,620)			—		(30,443)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.		$	35,347	$	(41,682)	$	30,097	$	(75,906)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units		(18,684)		(18,684)		(37,368)		(37,368)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.										NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	49,344	$	35,347		$	47,700	$	30,097
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units										Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(22,910)		(18,684)			(46,912)		(37,368)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS	NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS	$	16,663	$	(60,366)	$	(7,271)	$	(113,274)	NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS	$	26,434	$	16,663		$	788	$	(7,271)
NET INCOME (LOSS) PER COMMON UNIT (Note 11):
NET INCOME (LOSS) PER COMMON UNIT (Note 12):										NET INCOME (LOSS) PER COMMON UNIT (Note 12):

Basic and Diluted	Basic and Diluted	$	0.14	$	(0.49)	$	(0.06)	$	(0.92)	Basic and Diluted	$	0.22	$	0.14		$	0.01	$	(0.06)
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			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
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Net income (loss) $ 69,515 $ (35,780) $ 73,964 $ (65,215)
Other comprehensive income:
Amortization of prior year service cost 121 121 243 243
Total Comprehensive income (loss) 69,636 (35,659) 74,207 (64,972)
Comprehensive income attributable to noncontrolling interests (11,548) (136) (13,424) (134)
Comprehensive income attributable to redeemable noncontrolling interests (22,620) (5,766) (30,443) (10,557)
Comprehensive income (loss) attributable to Genesis Energy, L.P. $ 35,468 $ (41,561) $ 30,340 $ (75,663)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income	$	55,678	$	69,515	$	59,066	$	73,964
Other comprehensive income:
Decrease in benefit plan liability	121		121		243		243
Total Comprehensive income	55,799		69,636		59,309		74,207
Comprehensive income attributable to noncontrolling interests	(6,334)		(11,548)		(11,366)		(13,424)
Comprehensive income attributable to redeemable noncontrolling interests	—		(22,620)		—		(30,443)
Comprehensive income attributable to Genesis Energy, L.P.	$	49,465	$	35,468	$	47,943	$	30,340

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, March 31, 2022 122,579 $ 597,783 $ 293,451 $ (5,485) $ 885,749
Net income — 35,347 11,548 — 46,895
Cash distributions to partners — (18,387) — — (18,387)
Cash distributions to noncontrolling interests — — (13,130) — (13,130)
Cash contributions from noncontrolling interests — — 7,977 — 7,977
Other comprehensive income — — — 121 121
Distributions to Class A Convertible Preferred unitholders — (18,684) — — (18,684)
Partners’ capital, June 30, 2022 122,579 $ 596,059 $ 299,846 $ (5,364) $ 890,541
Number of Common Units Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, March 31, 2021 122,579 $ 758,031 $ (879) $ (9,243) $ 747,909
Net income (loss) — (41,682) 136 — (41,546)
Cash distributions to partners — (18,387) — — (18,387)
Cash contributions from noncontrolling interests — — 149 — 149
Other comprehensive income — — — 121 121
Distributions to Class A Convertible Preferred unitholders — (18,684) — — (18,684)
Partners’ capital, June 30, 2021 122,579 $ 679,278 $ (594) $ (9,122) $ 669,562
Number of Common Units Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, December 31, 2021 122,579 $ 641,313 $ 294,746 $ (5,607) $ 930,452
Net income — 30,097 13,424 — 43,521
Cash distributions to partners — (36,774) — — (36,774)
Adjustment to valuation of noncontrolling interest in subsidiary — (1,209) 1,209 — —
Cash distributions to noncontrolling interests — — (18,332) — (18,332)
Cash contributions from noncontrolling interests — — 8,799 — 8,799
Other comprehensive income — — — 243 243
Distributions to Class A Convertible Preferred unitholders — (37,368) — — (37,368)
Partners’ capital, June 30, 2022 122,579 $ 596,059 $ 299,846 $ (5,364) $ 890,541
Number of Common Units Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, December 31, 2020 122,579 $ 829,326 $ (1,113) $ (9,365) $ 818,848
Net income (loss) — (75,906) 134 — (75,772)
Cash distributions to partners — (36,774) — — (36,774)
Cash contributions from noncontrolling interests — — 385 — 385
Other comprehensive income — — — 243 243
Distributions to Class A Convertible Preferred unitholders — (37,368) — — (37,368)
Partners’ capital, June 30, 2021 122,579 $ 679,278 $ (594) $ (9,122) $ 669,562


	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Income		Total
Partners’ capital, March 31, 2023	122,579	$	523,244	$	319,269	$	6,236	$	848,749
Net income	—	49,344		6,334		—		55,678
Cash distributions to partners	—	(18,387)		—		—		(18,387)
Cash distributions to noncontrolling interests	—	—		(7,218)		—		(7,218)
Cash contributions from noncontrolling interests	—	—		15,840		—		15,840
Other comprehensive income	—	—		—		121		121
Distributions and returns attributable Class A Convertible Preferred unitholders	—	(22,910)		—		—		(22,910)


Partners’ capital, June 30, 2023	122,579	$	531,291	$	334,225	$	6,357	$	871,873

	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total
Partners’ capital, March 31, 2022	122,579	$	597,783	$	293,451	$	(5,485)	$	885,749
Net income	—	35,347		11,548		—		46,895
Cash distributions to partners	—	(18,387)		—		—		(18,387)

Cash distributions to noncontrolling interest	—	—		(13,130)		—		(13,130)
Cash contributions from noncontrolling interests	—	—		7,977		—		7,977
Other comprehensive income	—	—		—		121		121
Distributions and returns attributable Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)
Partners’ capital, June 30, 2022	122,579	$	596,059	$	299,846	$	(5,364)	$	890,541


	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Income		Total
Partners’ capital, December 31, 2022	122,579	$	567,277	$	310,162	$	6,114	$	883,553
Net income	—	47,700		11,366		—		59,066
Cash distributions to partners	—	(36,774)		—		—		(36,774)

Cash distributions to noncontrolling interests	—	—		(22,223)		—		(22,223)
Cash contributions from noncontrolling interests	—	—		34,920		—		34,920
Other comprehensive income	—	—		—		243		243
Distributions and returns attributable Class A Convertible Preferred unitholders	—	(46,912)		—		—		(46,912)


Partners’ capital, June 30, 2023	122,579	$	531,291	$	334,225	$	6,357	$	871,873

	Number of Common Units	Partners’ Capital		Noncontrolling Interest		Accumulated Other Comprehensive Loss		Total
Partners’ capital, December 31, 2021	122,579	$	641,313	$	294,746	$	(5,607)	$	930,452
Net income	—	30,097		13,424		—		43,521
Cash distributions to partners	—	(36,774)		—		—		(36,774)
Adjustment to valuation of noncontrolling interest in subsidiary	—	(1,209)		1,209		—		—
Cash distributions to noncontrolling interest	—	—		(18,332)		—		(18,332)
Cash contributions from noncontrolling interests	—	—		8,799		—		8,799
Other comprehensive income	—	—		—		243		243
Distributions and returns attributable Class A Convertible Preferred unitholders	—	(37,368)		—		—		(37,368)
Partners’ capital, June 30, 2022	122,579	$	596,059	$	299,846	$	(5,364)	$	890,541

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)


		Six Months Ended June 30,					Six Months Ended June 30,
		2022		2021			2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES:	CASH FLOWS FROM OPERATING ACTIVITIES:					CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	73,964	$	(65,215)
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Net income						Net income	$	59,066	$	73,964
Adjustments to reconcile net income to net cash provided by operating activities -						Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	Depreciation, depletion and amortization	143,179		133,827		Depreciation, depletion and amortization	141,587		143,179

Gain on sale of asset	Gain on sale of asset	(40,000)		—		Gain on sale of asset	—		(40,000)

Amortization and write-off of debt issuance costs, premium and discount	Amortization and write-off of debt issuance costs, premium and discount	4,652		6,965		Amortization and write-off of debt issuance costs, premium and discount	5,813		4,652

Payments received under previously owned direct financing leases		—		35,000

Equity in earnings of investments in equity investees	Equity in earnings of investments in equity investees	(27,016)		(34,882)		Equity in earnings of investments in equity investees	(32,364)		(27,016)
Cash distributions of earnings of equity investees	Cash distributions of earnings of equity investees	27,378		34,325		Cash distributions of earnings of equity investees	31,316		27,378
Non-cash effect of long-term incentive compensation plans	Non-cash effect of long-term incentive compensation plans	6,644		2,884		Non-cash effect of long-term incentive compensation plans	9,656		6,644
Deferred and other tax liabilities	Deferred and other tax liabilities	600		402		Deferred and other tax liabilities	551		600
Unrealized losses (gains) on derivative transactions	Unrealized losses (gains) on derivative transactions	(10,284)		32,377		Unrealized losses (gains) on derivative transactions	30,021		(10,284)
Cancellation of debt income	Cancellation of debt income	(4,737)		—		Cancellation of debt income	—		(4,737)
Other, net	Other, net	10,137		11,229		Other, net	8,718		10,137
Net changes in components of operating assets and liabilities (Note 14)		(26,230)		31,272
Net changes in components of operating assets and liabilities (Note 15)						Net changes in components of operating assets and liabilities (Note 15)	957		(26,230)
Net cash provided by operating activities	Net cash provided by operating activities	158,287		188,184		Net cash provided by operating activities	255,321		158,287
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	(181,441)		(111,412)		Payments to acquire fixed and intangible assets	(247,361)		(181,441)
Cash distributions received from equity investees - return of investment	Cash distributions received from equity investees - return of investment	10,372		17,015		Cash distributions received from equity investees - return of investment	13,300		10,372
Investments in equity investees	Investments in equity investees	(2,976)		—		Investments in equity investees	(2,197)		(2,976)

Proceeds from asset sales	Proceeds from asset sales	40,131		32		Proceeds from asset sales	202		40,131

Other, net						Other, net	4,332		—
Net cash used in investing activities	Net cash used in investing activities	(133,914)		(94,365)		Net cash used in investing activities	(231,724)		(133,914)
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	403,000		366,600		Borrowings on senior secured credit facility	501,976		403,000
Repayments on senior secured credit facility	Repayments on senior secured credit facility	(417,400)		(592,100)		Repayments on senior secured credit facility	(573,776)		(417,400)
Net proceeds from issuance of Alkali senior secured notes (Note 9)		408,000		—
Redemption of preferred units (Note 10)		(288,629)		—
Proceeds from issuance of senior unsecured notes (Note 9)		—		259,375
Net proceeds from issuance of preferred units (Note 10)		—		53,018
Repayment of senior unsecured notes (Note 9)		(40,837)		(80,859)
Net proceeds from issuance of Alkali senior secured notes (Note 10)						Net proceeds from issuance of Alkali senior secured notes (Note 10)	—		408,000
Redemption of redeemable noncontrolling interests (Note 1 1)						Redemption of redeemable noncontrolling interests (Note 1 1)	—		(288,629)
Proceeds from issuance of 2030 Notes (Note 10)						Proceeds from issuance of 2030 Notes (Note 10)	500,000		—
Repayment of senior unsecured notes (Note 10)						Repayment of senior unsecured notes (Note 10)	(341,135)		(40,837)
Debt issuance costs	Debt issuance costs	(5,770)		(11,365)		Debt issuance costs	(14,269)		(5,770)

Contributions from noncontrolling interests	Contributions from noncontrolling interests	8,799		385		Contributions from noncontrolling interests	34,920		8,799
Distributions to noncontrolling interests	Distributions to noncontrolling interests	(18,332)		—		Distributions to noncontrolling interests	(22,223)		(18,332)
Distributions to common unitholders	Distributions to common unitholders	(36,774)		(36,774)		Distributions to common unitholders	(36,774)		(36,774)
Distributions to Class A Convertible Preferred unitholders	Distributions to Class A Convertible Preferred unitholders	(37,368)		(37,368)		Distributions to Class A Convertible Preferred unitholders	(48,019)		(37,368)
Redemption of Class A Convertible Preferred Units						Redemption of Class A Convertible Preferred Units	(25,000)		—
Other, net	Other, net	4,462		4,539		Other, net	4,446		4,462
Net cash used in financing activities	Net cash used in financing activities	(20,849)		(74,549)		Net cash used in financing activities	(19,854)		(20,849)
Net increase in cash, cash equivalents and restricted cash	Net increase in cash, cash equivalents and restricted cash	3,524		19,270		Net increase in cash, cash equivalents and restricted cash	3,743		3,524
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	24,992		27,018		Cash, cash equivalents and restricted cash at beginning of period	26,567		24,992
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	28,516	$	46,288	Cash, cash equivalents and restricted cash at end of period	$	30,310	$	28,516

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 founded in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry as well as the production of natural soda ash. Our operations are primarily located in the Gulf Coast region of the United States, Wyoming and in the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers and industrial and commercial ~~enterprises and~~enterprises. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (our “Alkali Business”), refinery-related plants, storage tanks and terminals, railcars, ~~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 4four divisions that constitute our reportable segments:

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

•~~Sodium minerals~~Soda and sulfur services involving trona and trona-based exploring, mining, processing, soda ash production, marketing, logistics and selling activities, as well as ~~soda ash production and~~ 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~~includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum ~~products (primarily fuel oil, asphalt and other heavy refined products);~~products; and

•Marine transportation to provide waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North ~~America~~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.~~subsidiaries.

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, ~~2021~~2022 (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.

2. Recent Accounting Developments

~~Recent and Proposed Accounting Pronouncements~~

~~In March 2020, the FASB~~We are currently evaluating new accounting pronouncements that have been issued, ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (“LIBOR”) and other rates resulting from rate reform that are entered into on or before December 31, 2022. Contract terms that are modified due to the replacement of a reference ratebut are not ~~required~~yet effective. At this time, they are not expected to ~~be remeasured or reassessed under relevant accounting standards. On May 17, 2022, we entered into our Second Amendment and Consent to the credit agreement (defined in~~ ~~Note 9~~), which among other things, replaced our existing LIBOR rate based borrowings with the Term SOFR rate, which is based on the Secured Overnight Financing Rate (“SOFR”) borrowings. The impact to our senior secured credit facility and related interest expense upon transition to SOFR did not have a material impact on our ~~Unaudited Condensed Consolidated Financial Statements. Refer to~~ financial positions or results of operations.

~~Note 9~~ ~~for more details.~~

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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 three months ended June 30, ~~2022~~2023 and ~~2021,~~2022, respectively:


		Three Months Ended June 30, 2022											Three Months Ended June 30, 2023
		Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated			Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	Fee-based revenues	$	82,085	$	—	$	76,320	$	20,471	$	178,876	Fee-based revenues	$	91,459	$	—	$	77,343	$	13,897	$	182,699
Product Sales	Product Sales	—		287,940		—		224,241		512,181		Product Sales	—		440,301		—		159,108		599,409
Refinery Services	Refinery Services	—		30,668		—		—		30,668		Refinery Services	—		22,554		—		—		22,554
		$	82,085	$	318,608	$	76,320	$	244,712	$	721,725		$	91,459	$	462,855	$	77,343	$	173,005	$	804,662


		Three Months Ended June 30, 2021											Three Months Ended June 30, 2022
		Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated			Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated
Fee-based revenues	Fee-based revenues	$	73,221	$	—	$	47,626	$	18,176	$	139,023	Fee-based revenues	$	82,085	$	—	$	76,320	$	20,471	$	178,876
Product Sales	Product Sales	—		212,434		—		127,745		340,179		Product Sales	—		287,940		—		224,241		512,181
Refinery Services	Refinery Services	—		24,653		—		—		24,653		Refinery Services	—		30,668		—		—		30,668
		$	73,221	$	237,087	$	47,626	$	145,921	$	503,855		$	82,085	$	318,608	$	76,320	$	244,712	$	721,725

The following tables reflect the disaggregation of our revenues by major category for the six months ended June 30, ~~2022~~2023 and ~~2021,~~2022, respectively:

Six Months Ended
June 30, 2022
Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated
Fee-based revenues $ 150,153 $ — $ 132,094 $ 34,103 $ 316,350
Product Sales — 546,715 — 433,040 979,755
Refinery Services — 57,567 — — 57,567
$ 150,153 $ 604,282 $ 132,094 $ 467,143 $ 1,353,672


	Six Months Ended June 30, 2023
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	182,854	$	—	$	160,569	$	28,081	$	371,504
Product Sales	—		863,125		—		316,267		1,179,392
Refinery Services	—		44,378		—		—		44,378
	$	182,854	$	907,503	$	160,569	$	344,348	$	1,595,274

Six Months Ended
June 30, 2021
Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Marine Transportation Onshore Facilities and Transportation Consolidated
Fee-based revenues $ 137,605 $ — $ 87,957 $ 42,570 $ 268,132
Product Sales — 417,212 — 292,568 709,780
Refinery Services — 47,162 — — 47,162
$ 137,605 $ 464,374 $ 87,957 $ 335,138 $ 1,025,074


	Six Months Ended June 30, 2022
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	150,153	$	—	$	132,094	$	34,103	$	316,350
Product Sales	—		546,715		—		433,040		979,755
Refinery Services	—		57,567		—		—		57,567
	$	150,153	$	604,282	$	132,094	$	467,143	$	1,353,672

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

We did not have any contract assets at December 31, 2022 or June 30, 2023. The table below depicts our contract ~~asset and~~ liability balances at December 31, ~~2021~~2022 and June 30, ~~2022:~~2023:

Contract Assets Contract Liabilities
Current Assets- Other Accrued Liabilities Other Long-Term Liabilities
Balance at December 31, 2021 $ 13,563 $ 2,619 $ 19,028
Balance at June 30, 2022 751 11,898 26,369


	Contract Liabilities
	Accrued Liabilities		Other Long-Term Liabilities
Balance at December 31, 2022	$	2,087	$	64,478
Balance at June 30, 2023	3,129		85,833

Transaction Price Allocations to Remaining Performance Obligations

We are required to disclose the aggregate amount of our transaction prices that are allocated to unsatisfied performance obligations as of June 30, ~~2022. We~~2023. However, we are ~~exempt from disclosing performance~~permitted to utilize the following exemptions:

1)Performance obligations that are part of a contract with aan expected duration of one year or ~~less, revenue~~less;

2)Revenue recognized ~~related to~~from the satisfaction of performance obligations where ~~the~~we have a right to consideration in an amount that corresponds directly with the value provided to ~~customers~~customers; and ~~contracts with~~

3)Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated ~~wholly~~entirely to ana wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that is part of a ~~series in accordance with ASC 606.~~series.

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~~and include 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~~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 2022		$	38,085	$	3,600
2023		66,418		7,200
Remainder of 2023						Remainder of 2023	$	39,632	$	3,600
2024	2024	59,637		1,800		2024	75,546		1,800
2025	2025	63,279		—		2025	80,040		—
2026	2026	45,131		—		2026	52,952		—
2027						2027	14,743		—
Thereafter	Thereafter	57,612		—		Thereafter	43,006		—
Total	Total	$	330,162	$	12,600	Total	$	305,919	$	5,400

4. Business Consolidation

American Natural Soda Ash Corporation (“ANSAC”)

ANSAC is an organization whose purpose is to promote and market the use and sale of domestically produced natural soda ash in specified countries outside of the United States. Prior to 2023, our Alkali Business and another domestic soda ash producer were the two members of ANSAC. On January 1, 2023, we became the sole member of ANSAC and assumed 100% of the voting rights of the entity, and it became a wholly owned subsidiary of Genesis.

We will continue to supply levels of our soda ash produced in the Green River Basin to ANSAC to utilize their logistical and marketing capabilities as an export vehicle for our Alkali Business. We determined that ANSAC meets the definition of a business and will account for our acquisition of ANSAC as a business combination. We have reflected the financial results of ANSAC within our soda and sulfur services segment from the date of acquisition, January 1, 2023. The purchase price has been allocated to the assets acquired and the liabilities assumed based on our estimated preliminary fair

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values. We expect to finalize the purchase price allocation by the end of 2023. There was no consideration transferred as a result of becoming the sole member of ANSAC.

The preliminary allocation of the purchase price, as presented within our Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023 is summarized as follows:


Cash and cash equivalents	$	4,332
Accounts receivable - trade, net	231,797
Inventories	19,522
Other current assets	14,203
Fixed assets, at cost	4,000
Right of use assets, net	93,208
Intangible assets, net of amortization	11,181
Other Assets, net of amortization	2,728
Accounts payable - trade(1)	(228,106)
Accrued liabilities	(75,224)
Other long-term liabilities	(77,641)

Net Assets	$	—

(1)The “Accounts payable - trade” balance above includes $133.4 million of payables to Genesis at December 31, 2022 that eliminate upon consolidation into our Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023.

Inventories principally relate to finished goods (soda ash) that have been supplied by current or former members of ANSAC. “Fixed assets, at cost” relate to leasehold improvements, and “Intangible assets, net of amortization” relate to our assets supporting our logistical and marketing footprint, and both have an estimated useful life of ten years, which is consistent with the term of our primary lease facilitating our logistics operations. Right of use assets, net and our corresponding lease liabilities, which are recorded within “Accrued liabilities” and “Other long-term liabilities,” respectively, are associated with our right to use certain assets to store and load finished goods, the vessels we utilize to ship finished goods to distributors and end users, as well as office space.

Our Unaudited Condensed Consolidated Statement of Operations include the results of ANSAC since January 1, 2023. The following table presents selected financial information included in our Unaudited Consolidated Statement of Operations for the period presented:


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
Revenues	$	102,312	$	229,454
Net Income Attributable to Genesis Energy, L.P.	4,249		5,271

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The following unaudited pro forma financial information was prepared from our historical financial statements that have been adjusted to give the effect of the consolidation of ANSAC as though we had become the sole member on January 1, 2022. It is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using financial data of ANSAC and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had we become the sole member on January 1, 2022. Pro forma net income (loss) attributable to common unitholders includes the effects of distributions attributable to our Class A Preferred Units. The dilutive effect of our preferred units is calculated using the if-converted method.


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Pro forma consolidated financial operating results:
Revenues	$	804,662	$	824,037	$	1,595,274	$	1,583,126
Net Income Attributable to Genesis Energy, L.P.	49,344		39,596		47,700		35,368
Net Income (Loss) Attributable to Common Unitholders	26,434		20,912		788		(2,000)
Basic and diluted earnings (loss) per common unit:
As reported net income (loss) per common unit	$	0.22	$	0.14	$	0.01	$	(0.06)
Pro forma net income (loss) per common unit	$	0.22	$	0.17	$	0.01	$	(0.02)

4.5. Lease Accounting

Lessee Arrangements

We lease a variety of transportation equipment (primarily railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term ~~(under~~(not greater than 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use assets and associated lease liabilities. Leases with a term of ~~less than~~ 12 months or fewer are not recorded on our Unaudited Condensed Consolidated Balance Sheets, and we recognize lease expense for these leases 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~~leases as well as our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease. ~~Our lease liability includes our cease-use provision for railcars no longer in use. Our short-term~~Current and ~~long-term~~non-current 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~~certain contracts discussed below in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties.

Operating Leases

During the three and six months ended June 30, ~~2022~~2023 and ~~2021,~~2022, we acted as a lessor in a revenue contract associated with the M/T American Phoenix, ~~which is~~ included in our marine transportation segment. Our lease revenues for this arrangement ~~(inclusive of fixed and variable consideration)~~ were ~~$4.6~~$5.9 million and ~~$3.8~~$4.6 million for the three months ended June 30, ~~2022~~2023 and ~~2021,~~2022, respectively, and ~~$8.7~~$11.7 million and ~~$7.2~~$8.7 million for the six months ended June 30, ~~2022~~2023 and ~~2021,~~2022, respectively.

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6. Inventories

The major components of inventories were as follows:


		June 30, 2022		December 31, 2021			June 30, 2023		December 31, 2022
Petroleum products	Petroleum products	$	—	$	998	Petroleum products	$	—	$	56
Crude oil	Crude oil	20,767		11,834		Crude oil	28,198		6,673
Caustic soda	Caustic soda	10,031		5,690		Caustic soda	13,425		15,258
NaHS	NaHS	20,232		17,040		NaHS	9,721		7,085
Raw materials - Alkali operations		6,948		7,599
Work-in-process - Alkali operations		7,010		7,496
Finished goods, net - Alkali operations		12,633		13,681
Materials and supplies, net - Alkali operations		14,213		13,620
Raw materials - Alkali Business						Raw materials - Alkali Business	6,194		5,819
Work-in-process - Alkali Business						Work-in-process - Alkali Business	10,969		9,599
Finished goods, net - Alkali Business						Finished goods, net - Alkali Business	33,033		18,772
Materials and supplies, net - Alkali Business						Materials and supplies, net - Alkali Business	16,312		14,881

Total	Total	$	91,834	$	77,958	Total	$	117,852	$	78,143

Inventories are valued at the lower of cost or net realizable value. ~~There was 0 adjustment to the net realizable value~~As of ~~inventories during the period ended~~ June 30, ~~2022. As of~~2023 and December 31, ~~2021,~~2022, the net realizable value of inventories were below cost by ~~$2.0~~$0.1 million and $2.9 million, respectively, which triggered a reduction of the value of inventory in our Unaudited Condensed Consolidated Financial Statements by ~~this amount.~~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.

1113

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

6.7. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following:


	June 30, 2023		December 31, 2022
Crude oil and natural gas pipelines and related assets	$	2,846,411	$	2,844,288
Alkali facilities, machinery and equipment	731,112		701,313
Onshore facilities, machinery and equipment	270,352		269,949
Transportation equipment	23,819		22,340
Marine vessels	1,014,495		1,017,087
Land, buildings and improvements	238,521		231,651
Office equipment, furniture and fixtures	24,704		24,271
Construction in progress(1)	868,960		712,971
Other	41,168		41,168
Fixed assets, at cost	6,059,542		5,865,038
Less: Accumulated depreciation	(1,875,840)		(1,768,465)
Net fixed assets	$	4,183,702	$	4,096,573

June 30, 2022 December 31, 2021
Crude oil and natural gas pipelines and related assets $ 2,839,496 $ 2,839,443
Alkali facilities, machinery and equipment 684,289 670,880
Onshore facilities, machinery and equipment 269,139 269,245
Transportation equipment 21,216 21,106
Marine vessels 1,016,892 1,018,284
Land, buildings and improvements 228,725 227,540
Office equipment, furniture and fixtures 26,992 23,965
Construction in progress 471,595 350,137
Other 41,168 43,440
Fixed assets, at cost 5,599,512 5,464,040
Less: Accumulated depreciation (1,661,837) (1,551,855)
Net fixed assets $ 3,937,675 $ 3,912,185
(1)Construction in progress primarily relates to our Granger Optimization Project, which is expected to be completed in 2023, and our offshore growth capital projects, which are expected to be completed in 2024 and 2025.

Mineral Leaseholds

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


		June 30, 2022		December 31, 2021			June 30, 2023		December 31, 2022
Mineral leaseholds	Mineral leaseholds	$	566,019	$	566,019	Mineral leaseholds	$	566,019	$	566,019
Less: Accumulated depletion	Less: Accumulated depletion	(18,948)		(17,014)		Less: Accumulated depletion	(23,046)		(20,897)
Mineral leaseholds, net of accumulated depletion	Mineral leaseholds, net of accumulated depletion	$	547,071	$	549,005	Mineral leaseholds, net of accumulated depletion	$	542,973	$	545,122

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Depreciation expense	Depreciation expense	$	70,033	$	64,148	$	135,783	$	126,850	Depreciation expense	$	63,913	$	70,033	$	133,486	$	135,783
Depletion expense	Depletion expense	914		704		1,934		1,616		Depletion expense	1,268		914		2,149		1,934

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, ~~2021:~~2022:


ARO liability balance, December 31, ~~2021~~2022	$	~~220,906~~228,573
Accretion expense	~~6,871~~6,592
Changes in estimate	~~2,383~~3,915


Settlements	~~(9,798)~~(60)

ARO liability balance, June 30, ~~2022~~2023	$	~~220,362~~239,020

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

At June 30, ~~2022~~2023 and December 31, ~~2021, $30.6~~2022, $26.1 million and ~~$36.3~~$26.6 million are included as current in “Accrued liabilities” on our Unaudited Condensed Consolidated Balance Sheets, respectively. The remainder of the ARO liability as of June 30, ~~2022~~2023 and December 31, ~~2021~~2022 is included in “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheets.

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

Remainder of 2022 $ 6,291
2023 $ 10,583
2024 $ 9,767
2025 $ 10,469
2026 $ 8,216

Certain of our unconsolidated affiliates have AROs recorded at June 30, ~~2022~~2023 and December 31, ~~2021~~2022 relating to contractual agreements and regulatory requirements. In addition, certain entities that we consolidate have non-controlling interest owners that are responsible for their representative share of future costs of the related ARO liability. These amounts are immaterial to our Unaudited Condensed Consolidated Financial Statements.

7.8. Equity Investees

We account for our ownership in certain of 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 June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the unamortized excess cost amounts totaled ~~$312.8~~$298.5 million and ~~$319.9~~$305.6 million, respectively. We amortize the differences in carrying value as changes in equity earnings.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Genesis’ share of operating earnings	Genesis’ share of operating earnings	$	18,138	$	18,094	$	34,148	$	42,627	Genesis’ share of operating earnings	$	18,377	$	18,138	$	39,496	$	34,148
Amortization of differences attributable to Genesis’ carrying value of equity investments	Amortization of differences attributable to Genesis’ carrying value of equity investments	(3,566)		(3,872)		(7,132)		(7,745)		Amortization of differences attributable to Genesis’ carrying value of equity investments	(3,566)		(3,566)		(7,132)		(7,132)
Net equity in earnings	Net equity in earnings	$	14,572	$	14,222	$	27,016	$	34,882	Net equity in earnings	$	14,811	$	14,572	$	32,364	$	27,016
Distributions received(1)	Distributions received(1)	$	18,732	$	21,914	$	37,750	$	51,430	Distributions received(1)	$	20,678	$	18,732	$	44,512	$	37,750

(1) Includes distributions attributable to the period and received during or ~~promptly~~within 15 days following ~~such~~the period.

The following tables present the unaudited balance sheets and statements of operations information (on a 100% basis) for Poseidon Oil Pipeline Company, L.L.C. (“~~Poseidon”~~Poseidon,” and its pipeline and associated assets, the “Poseidon pipeline”) (which we own 64% of and is our most significant equity investment):


		June 30, 2022		December 31, 2021			June 30, 2023		December 31, 2022
BALANCE SHEETS DATA:	BALANCE SHEETS DATA:					BALANCE SHEETS DATA:
Assets	Assets					Assets
Current assets	Current assets	$	21,115	$	17,827	Current assets	$	23,888	$	27,878
Fixed assets, net	Fixed assets, net	152,979		160,379		Fixed assets, net	145,726		147,505
Other assets	Other assets	11,660		6,186		Other assets	16,394		13,419
Total assets	Total assets	$	185,754	$	184,392	Total assets	$	186,008	$	188,802
Liabilities and equity	Liabilities and equity					Liabilities and equity
Current liabilities	Current liabilities	$	9,121	$	7,668	Current liabilities	$	11,800	$	10,087
Other liabilities	Other liabilities	232,631		231,970		Other liabilities	238,917		236,813
Equity (Deficit)	Equity (Deficit)	(55,998)		(55,246)		Equity (Deficit)	(64,709)		(58,098)
Total liabilities and equity	Total liabilities and equity	$	185,754	$	184,392	Total liabilities and equity	$	186,008	$	188,802


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
STATEMENTS OF OPERATIONS DATA:
Revenues	$	39,251	$	35,380	$	80,146	$	66,569
Operating income	$	29,052	$	25,856	$	61,003	$	47,809
Net income	$	25,313	$	24,441	$	53,989	$	45,348

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
STATEMENTS OF OPERATIONS DATA:
Revenues $ 35,380 $ 33,757 $ 66,569 $ 76,170
Operating income $ 25,856 $ 24,636 $ 47,809 $ 56,797
Net income $ 24,441 $ 23,610 $ 45,348 $ 54,755

Poseidon’s Revolving Credit Facility

Borrowings under ~~Poseidon’s~~Poseidon’s revolving credit facility, which was amended and restated ~~in March 2019,~~on June 1, 2023 (the “June 2023 credit facility”), are primarily used to fund spending on capital projects. The ~~March 2019~~June 2023 credit facility, which matures on June 1, 2027, 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~~its assets. The June 2023 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.

8.9. Intangible Assets

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


		June 30, 2022						December 31, 2021							June 30, 2023						December 31, 2022
		Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value			Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Marine contract intangibles		$	800	$	625	$	175	$	800	$	607	$	193
Offshore pipeline contract intangibles	Offshore pipeline contract intangibles	158,101		57,554		100,547		158,101		53,394		104,707		Offshore pipeline contract intangibles	158,101		65,876		92,225		158,101		61,715		96,386
Other	Other	42,735		16,757		25,978		37,933		15,770		22,163		Other	61,789		15,734		46,055		45,191		14,257		30,934
Total	Total	$	201,636	$	74,936	$	126,700	$	196,834	$	69,771	$	127,063	Total	$	219,890	$	81,610	$	138,280	$	203,292	$	75,972	$	127,320

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

Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Amortization of intangible assets $ 2,577 $ 2,580 $ 5,165 $ 5,180


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Amortization of intangible assets	$	2,973	$	2,577	$	5,678	$	5,165

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

Remainder of 2022 $ 6,110
2023 $ 11,983
2024 $ 11,618
2025 $ 11,393
2026 $ 11,093


Remainder of	2023	$	7,071
	2024	13,907
	2025	13,646
	2026	13,334
	2027	12,887

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

9.10. Debt

Our obligations under debt arrangements consisted of the following:


		June 30, 2022						December 31, 2021							June 30, 2023						December 31, 2022
		Principal		Unamortized Premium, Discount and Debt Issuance Costs		Net Value		Principal		Unamortized Premium and Debt Issuance Costs		Net Value			Principal		Unamortized Premium, Discount and Debt Issuance Costs		Net Value		Principal		Unamortized Premium, Discount and Debt Issuance Costs		Net Value
Senior secured credit facility-Revolving Loan(1)		$	34,600	$	—	$	34,600	$	49,000	$	—	$	49,000

Senior secured credit facility(1)														Senior secured credit facility(1)	$	133,600	$	—	$	133,600	$	205,400	$	—	$	205,400
5.625% senior unsecured notes due 2024	5.625% senior unsecured notes due 2024	341,135		1,678		339,457		341,135		2,106		339,029		5.625% senior unsecured notes due 2024	—		—		—		341,135		1,249		339,886
6.500% senior unsecured notes due 2025	6.500% senior unsecured notes due 2025	534,834		3,858		530,976		534,834		4,452		530,382		6.500% senior unsecured notes due 2025	534,834		2,672		532,162		534,834		3,265		531,569
6.250% senior unsecured notes due 2026	6.250% senior unsecured notes due 2026	344,310		2,890		341,420		359,799		3,410		356,389		6.250% senior unsecured notes due 2026	339,310		2,113		337,197		339,310		2,481		336,829
8.000% senior unsecured notes due 2027	8.000% senior unsecured notes due 2027	1,000,000		5,809		994,191		1,000,000		6,592		993,408		8.000% senior unsecured notes due 2027	981,245		4,239		977,006		981,245		4,956		976,289
7.750% senior unsecured notes due 2028	7.750% senior unsecured notes due 2028	690,890		8,512		682,378		720,975		9,678		711,297		7.750% senior unsecured notes due 2028	679,360		6,871		672,489		679,360		7,621		671,739
5.875% Alkali senior secured notes due 2042		425,000		22,796		402,204		—		—		—
8.875% senior unsecured notes due 2030														8.875% senior unsecured notes due 2030	500,000		9,004		490,996		—		—		—
5.875% Alkali senior secured notes due 2042(2)														5.875% Alkali senior secured notes due 2042(2)	425,000		22,178		402,822		425,000		22,558		402,442
Total long-term debt	Total long-term debt	$	3,370,769	$	45,543	$	3,325,226	$	3,005,743	$	26,238	$	2,979,505	Total long-term debt	$	3,593,349	$	47,077	$	3,546,272	$	3,506,284	$	42,130	$	3,464,154

(1)Unamortized debt issuance costs associated with our ~~Revolving Loan, as defined below~~senior secured credit facility (included in “Other Assets, net of amortization” on the Unaudited Condensed Consolidated Balance Sheets), ~~under our senior secured credit facility~~ were ~~$3.7~~$6.7 million and ~~$4.7~~$2.6 million as of June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively.

(2)As of June 30, 2023, $5.8 million of the principal balance is considered current and included within “Accrued liabilities” on the Unaudited Condensed Consolidated Balance Sheet.

Senior Secured Credit Facility

On ~~April 8, 2021,~~February 17, 2023, we entered into the Sixth Amended and Restated Credit Agreement (our “new credit agreement”) to replace our Fifth Amended and Restated Credit ~~Agreement (the “credit agreement”) to replace our Fourth Amended and Restated Credit Agreement, which~~Agreement. Our new credit agreement provides for a ~~$950~~$850 million senior secured revolving credit facility, comprised of a revolving loan facility with a borrowing capacity of $650 million (the “Revolving Loan”) and a term loan facility of $300 million (the “Term Loan”). We repaid the Term Loan in full on November 17, 2021 with a portion of the proceeds received from our sale of a 36% minority interest in CHOPS (~~Note 10~~).facility. The new credit agreement matures on ~~March 15, 2024,~~February 13, 2026, subject to extension at our request for one additional year on up to two occasions and subject to certain ~~conditions.~~

~~On May 17, 2022, we entered into~~conditions, unless more than $150 million of our ~~Second Amendment and Consent to~~2025 Notes remain outstanding as of June 30, 2025, in which case the new credit agreement (the “credit agreement amendment”). This credit agreement amendment, among other things, permitted the entry into and performance of the transactions and agreements secured by the ORRI Interests (as defined below) and replaced our existing LIBOR rate based borrowings with Term SOFR rate, which is a forward looking term rate basedmatures on ~~SOFR, discussed in further detail below.~~such date.

At June 30, ~~2022,~~2023, the key terms for rates under our ~~Revolving Loan~~senior secured credit facility (which are dependent on our leverage ratio as defined in the new credit ~~agreement amendment)~~agreement) are as follows:

•The interest rate on borrowings may be based on an alternate base rate or Term SOFR, at our option. Interest on alternate base rate loans is equal to the sum of (a) the highest of (i) the prime rate in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% and (iii) the Adjusted Term SOFR (as defined in our new credit ~~agreement amendment)~~agreement) for a one-month tenor in effect on such day plus 1% and (b) the applicable margin. The Adjusted Term SOFR is equal to the sum of (a) the Term SOFR rate (as defined in our new credit ~~agreement amendment)~~agreement) for such period plus (b) the Term SOFR Adjustment of 0.1% plus (c) the applicable margin. The applicable margin varies from 2.25% to ~~3.75%~~3.50% on Term SOFR borrowings and from 1.25% to ~~2.75%~~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 June 30, ~~2022,~~2023, the applicable margins on our borrowings were ~~2.50%~~1.75% for alternate base rate borrowings and ~~3.50%~~2.75% for Term SOFR borrowings based on our leverage ratio.

•Letter of credit fee rates range from 2.25% to ~~3.75%~~3.50% based on our leverage ratio as computed under the credit agreement and can fluctuate quarterly. At June 30, ~~2022,~~2023, our letter of credit rate was ~~3.50%~~2.75%.

•We pay a commitment fee on the unused portion of the ~~Revolving Loan.~~senior secured revolving credit facility. The commitment fee rates on the unused committed amount will range from 0.30% to 0.50% per annum depending on our leverage ratio. At June 30, ~~2022,~~2023, our commitment fee rate on the unused committed amount was 0.50%.

•We have the ability to increase the aggregate size of the ~~Revolving Loan~~senior secured credit facility by an additional $200 million, subject to lender consent and certain other customary conditions.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

At June 30, ~~2022,~~2023, we had ~~$34.6~~$133.6 million ~~outstanding~~borrowed under our ~~Revolving Loan,~~new credit agreement, with ~~$14.3~~$16.3 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to ~~$100.0~~$100 million of the capacity to be used for letters of credit, of which ~~$4.5~~$8.5 million was outstanding at June 30, ~~2022.~~2023. Due to the revolving nature of loans under our ~~Revolving Loan,~~senior secured credit facility, additional borrowings, periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our ~~Revolving Loan~~senior secured credit facility at June 30, ~~2022~~2023 was ~~$610.9~~$707.9 million, subject to compliance with covenants. Our new credit agreement does not include a “borrowing base” limitation except with respect to our inventory loans.

Alkali Senior Secured Notes Issuance and Related Transactions

On May 17, 2022, Genesis Energy, L.P., through its newly created wholly-owned unrestricted subsidiary, GA ORRI, LLC (“GA ORRI”), issued $425 million principal amount of our 5.875% senior secured notes due 2042 (the “Alkali senior secured notes”) to certain institutional investors (the “Notes Offering”), secured by GA ORRI’s fifty-year limited term overriding royalty interest in substantially all of the Alkali Business’ trona mineral leases (the “ORRI Interests”). Interest payments are due on the last day of each quarter with the initial interest payment ~~due~~made on June 30, 2022. The agreement governing the Alkali senior secured notes also requires principal repayments on the last day of each quarter commencing with the first quarter of 2024. ~~Principal~~As of June 30, 2023, principal repayments totaling ~~$46.2~~$61.4 million are due within the next five years, with the remaining quarterly principal repayments due thereafter through March 31, ~~2042, as outlined in the agreement governing the Alkali senior secured notes.~~2042. ~~The issuance generated net proceeds~~As of ~~$408 million, net of the issuance discount of $17 million. We transferred $18.4~~June 30, 2023, $5.8 million of the ~~net proceeds into~~principal balance is considered current and included within “Accrued liabilities” on the Unaudited Condensed Consolidated Balance Sheet.We are required to maintain a certain level of cash in a liquidity reserve account ~~owned~~(owned by GA ~~ORRI~~ORRI) to be held as collateral for future interest and principal payments as calculated and described in the agreement governing the Alkali senior secured ~~notes, which proceeds held in the~~notes. As of June 30, 2023, our liquidity reserve account ~~are~~had a balance of $18.8 million, which is classified as “Restricted cash” on the Unaudited Condensed Consolidated Balance Sheet. The issuance generated net proceeds of $408 million, net of the issuance discount of $17 million. We used a portion of the ~~remaining~~ net proceeds from the issuance to fully redeem the outstanding Alkali Holdings preferred units (as defined and further discussed in Note 1011) and utilized the remainder to repay a portion of the outstanding borrowings under ~~the credit agreement.~~

Additionally, on May 17, 2022, as noted above, we entered into our credit agreement amendment. This amendment also designated GA ORRI and its direct parent, GA ORRI Holdings, LLC (“GA ORRI Holdings”), as unrestricted subsidiaries under our credit agreement. We also designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries under the indentures governing our 5.625% senior notes due 2024, 6.50% senior notes due 2025, 6.250% senior notes due 2026, 2027 Notes (defined below) and 7.750% senior notes due 2028. On May 17, we also reclassified the subsidiaries originally held by our Alkali Business as restricted subsidiaries under our credit agreement and under the indentures governing our senior ~~unsecured notes.~~secured credit facility as well as fund our liquidity reserve account.

Senior Unsecured Note Transactions

On ~~December 17, 2020,~~January 25, 2023, we issued ~~$750~~$500.0 million in aggregate principal amount of ~~our 8.00%~~8.875% senior unsecured notes due ~~January~~April 15, ~~2027~~2030 (the ~~“2027~~“2030 Notes”). Interest payments are due ~~on January~~April 15 and ~~July~~October 15 of each year with the initial interest payment due on ~~July~~October 15, ~~2021.~~2023. The ~~issuance generated~~ net proceeds ~~of approximately $737 million, net of issuance costs incurred. We~~were used ~~$316.5~~to purchase $316.3 million of our existing 2024 Notes, including the ~~net proceeds to repay the portion of the 6.00% senior unsecured notes due May 15, 2023 (the “2023 Notes”) (including principal,~~related accrued interest and tender ~~premium)~~premium and fees on those notes that were ~~validly~~ tendered ~~and~~in the tender offer that ended January 24, 2023. The remaining proceeds at that time were used to repay a portion of the borrowings outstanding under our ~~revolving~~senior secured credit ~~facility.~~ facility and for general partnership purposes.

On January ~~19, 2021,~~26, 2023, we ~~redeemed~~issued a notice of redemption for the remaining principal ~~balance outstanding on our 2023 Notes~~ of ~~$80.9~~$24.8 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~~2024 Notes ~~inclusive of~~and discharged the redemption fee and the write-off of the related unamortized debt issuance costs, which is recorded in “Other income (expense)” in our Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30, 2021.

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 thanindebtedness with respect to the ~~issue price) and constitute part of the same series of the 2027 Notes. The $250 million of the 2027~~2024 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our credit agreement.

~~During 2022, we repurchased certain of our senior unsecured notes~~ on the open market and recorded cancellation of debt income of $4.7 million for the three and six months ended June 30, 2022. These are recorded within “Other income (expense)” in our Unaudited Consolidated Statements of Operations.February 14, 2023.

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except GA ORRI and GA ORRI Holdings, LLC (“GA ORRI Holdings”), and certain other subsidiaries. The non-guarantor subsidiaries are indirectly owned by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets, other than the ORRI Interests, that we use to operate our business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries.

~~10.~~11. Partners’ Capital, Mezzanine Capital and Distributions

At June 30, ~~2022,~~2023, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and, accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to certain exceptions. At June 30, ~~2022,~~2023, we had ~~25,336,778~~24,595,158 Class A Convertible Preferred Units outstanding, which are discussed below in further detail.

Table of Contents

Distributions

We paid or will pay the following cash distributions to our common unitholders in ~~2021~~2022 and ~~2022:~~2023:


Distribution For	Distribution For	Date Paid		Per Unit Amount		Total Amount		Distribution For	Date Paid	Per Unit Amount		Total Amount

2021
1st Quarter		May 14, 2021		$	0.15	$	18,387
2nd Quarter(1)		August 13, 2021		$	0.15	$	18,387
3rd Quarter		November 12, 2021		$	0.15	$	18,387
4th Quarter		February 14, 2022		$	0.15	$	18,387
2022	2022							2022
1st Quarter	1st Quarter	May 13, 2022		$	0.15	$	18,387	1st Quarter	May 13, 2022	$	0.15	$	18,387
2nd Quarter	2nd Quarter	August 12, 2022	(1)	$	0.15	$	18,387	2nd Quarter	August 12, 2022	$	0.15	$	18,387
3rd Quarter								3rd Quarter	November 14, 2022	$	0.15	$	18,387
4th Quarter								4th Quarter	February 14, 2023	$	0.15	$	18,387
2023								2023
1st Quarter								1st Quarter	May 15, 2023	$	0.15	$	18,387
2nd Quarter(1)								2nd Quarter(1)	August 14, 2023	$	0.15	$	18,387

(1)This distribution was declared onin July ~~12, 2022~~2023 and will be paid to unitholders of record as of July ~~29, 2022.~~31, 2023.

Class A Convertible Preferred Units

Our Class A Convertible Preferred Units rank senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those Class A Convertible Preferred Units.

Accounting for the Class A Convertible Preferred Units

Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event that is outside of our control. Therefore, we present them as temporary equity in the mezzanine section of the 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~~costs, as they were not redeemable and we did not have plans or expect any events that constitute a change of control in our partnership agreement. Additionally, our Class A Convertible Preferred Units contained a distribution Rate Reset Election (as defined in Note 16), which was elected by the holders of the Class A Convertible Preferred Units on September 29, 2022 (the “Election Date”). From the date of issuance through the Election Date, this distribution rate reset feature was bifurcated and accounted for separately as an embedded derivative and recorded at fair value at each reporting period. As of the Election Date, the feature within the Class A Convertible Preferred Units that required bifurcation no longer existed and we adjusted the carrying value of the Class A Convertible Preferred Units to include the fair value of the previously bifurcated embedded derivative at the Election Date. Refer to Note 16 for additional discussion.

On April 3, 2023, we entered into a purchase agreement with the Class A Convertible Preferred unitholders whereby we redeemed 741,620 Class A Convertible Preferred Units (the “Redeemed Units”) at a purchase price of $33.71 per unit. The Redeemed Units had a carrying value of $35.20 per unit resulting in a return attributable to the Class A Convertible Preferred Units of approximately $1.1 million. In addition, we paid a distribution of $0.9681 per Redeemed Unit, which represented distributions that accrued from January 1, 2023 through April 2, 2023.

Net Income Attributable to Genesis Energy, L.P. is adjusted for distributions and returns attributable to the Class A Convertible Preferred Units that accumulate in the period. Net Income Attributable to Genesis Energy, L.P. was reduced by $24.0 million and $48.0 million for the three and six months ending June 30, 2023, respectively, and $18.7 million and $37.4 million, for the three and six months ending June 30, 2022, respectively, due to Class A Convertible Preferred Unit distributions accumulated in the period (Class A Convertible Preferred Unit distributions are summarized in the table below). For the three and six months ended June 30, 2023, Net Income Attributable to Genesis Energy L.P. was increased by $1.1 million due to returns attributable to the Class A Convertible Preferred Units accumulated in the period.

As of June 30, 2023, we will not be required to further adjust the carrying amount of our Class A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our Class A Convertible Preferred Units to the redemption value over a period of time comprising the date ~~the feature~~redemption 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). 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.~~

1719

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Net Income (Loss) Attributable to Genesis Energy, L.P. is reduced by Class A Convertible Preferred Unit distributions that accumulated during the period and was reduced by $18.7 million and $37.4 million for the three and six months ended June 30, 2022 and 2021, respectively.

We paid, or will pay, by the dates noted below, the following cash distributions to our Class A Convertible Preferred unitholders in ~~2021~~2022 and ~~2022:~~2023:


Distribution For	Distribution For	Date Paid		Per Unit Amount		Total Amount		Distribution For	Date Paid	Per Unit Amount		Total Amount

2021
2022								2022
1st Quarter	1st Quarter	May 14, 2021		$	0.7374	$	18,684	1st Quarter	May 13, 2022	$	0.7374	$	18,684
2nd Quarter	2nd Quarter	August 13, 2021		$	0.7374	$	18,684	2nd Quarter	August 12, 2022	$	0.7374	$	18,684
3rd Quarter	3rd Quarter	November 12, 2021		$	0.7374	$	18,684	3rd Quarter	November 14, 2022	$	0.7374	$	18,684
4th Quarter	4th Quarter	February 14, 2022		$	0.7374	$	18,684	4th Quarter	February 14, 2023	$	0.9473	$	24,002
2022
2023								2023
1st Quarter(1)	1st Quarter(1)	May 13, 2022		$	0.7374	$	18,684	1st Quarter(1)	May 15, 2023	$	0.9473	$	24,002
2nd Quarter(2)	2nd Quarter(2)	August 12, 2022	(1)	$	0.7374	$	18,684	2nd Quarter(2)	August 14, 2023	$	0.9473	$	23,314

(1)Approximately $0.7 million of this distribution associated with the Redeemed Units was paid on April 3, 2023.

(2)This distribution was declared onin July ~~12, 2022~~2023 and will be paid to unitholders of record as of July ~~29, 2022.~~31, 2023

As a result of the one-time Rate Reset Election made by the holders of the Class A Convertible Preferred Units on the Election Date, the annual distribution rate for the Class A Convertible Preferred Units increased from 8.75% to 11.24%, applicable for future quarterly distributions declared and payable, beginning with the quarter ended December 31, 2022.

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 Blackstone Alternative Credit Advisors LP, formerly known as “GSO Capital Partners LP” (collectively “BXC”) purchased $55.0 million (or 55,000 Alkali Holdings preferred units) and committed to purchase up to $350.0 million of Alkali Holdings preferred units, the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings utilized the net proceeds received from the issuance of the preferred units to fund a portion of the anticipated cost of expansion of the Granger facility (the “Granger Optimization Project” or “GOP”).

On April 14, 2020, we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of the GOP by one year, which we currently anticipate completing in the ~~third quarter~~second half of 2023. In consideration ~~for~~of the amendment, we issued 1,750 Alkali Holdings preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period was increased to four years, and the total commitment of BXC was increased to, subject to compliance with the covenants contained in the agreements with BXC, up to $351.8 million preferred units (or 351,750 preferred units) in Alkali Holdings.

From time to time after we had drawn at least $251.8 million, we had the option to redeem the outstanding preferred

units in whole for cash at a price equal to the initial $1,000 per preferred unit purchase price, plus no less than the greater of a

predetermined fixed internal rate of return amount (“IRR”) or a multiple of invested capital metric (“MOIC”), net of cash distributions paid to date (“Base Preferred Return Amount”). Additionally, if all outstanding preferred units were redeemed, we had not drawn at least $251.8 million, and BXC was not a “defaulting member” under the LLC Agreement, BXC had the right to a make-whole amount on the number of undrawn preferred units.

On May 17, 2022 (the “Redemption Date”), we fully redeemed the 251,750 outstanding Alkali Holdings preferred units at a Base Preferred Return Amount of $288.6 million utilizing a portion of the proceeds we received from the issuance of our Alkali senior secured notes. As of June 30, ~~2022,~~2023, there were 0no Alkali Holdings preferred units outstanding.

Accounting for Redeemable Noncontrolling Interests

Classification

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

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Initial and Subsequent Measurement

We recorded the Alkali Holdings preferred units at their issuance date fair value, net of issuance costs. The fair value of the Alkali Holdings preferred units was approximately $270.1 million as of May 16, 2022, which represented the carrying amount based on the issued and outstanding Alkali Holdings preferred units most probable redemption event on the six and a half year anniversary of the closing, which was the IRR measure accreted using the effective interest method to the redemption value as of each reporting date. On May 16, 2022, certain events occurred that made it probable that an early redemption event on the Alkali Holdings preferred units would occur and the outstanding preferred units would be redeemed at the MOIC, as it was greater than the IRR at the time of the redemption. This required the Company to revalue the Alkali Holdings preferred units to the redemption amount of $288.6 million, which represents the MOIC, net of cash distributions (including tax distributions) paid to date.

Net Income ~~(Loss)~~ Attributable to Genesis Energy, L.P. for the three and six months ended June 30, 2022 includes $22.6 million and $30.4 million of adjustments, respectively, of which $3.4 million and $10.0 million, respectively, was allocated to the paid-in-kind (“PIK”) distributions ~~on the outstanding Alkali Holdings preferred units,~~and $0.7 million and $1.9 million, respectively, was attributable to redemption accretion value adjustments, and $18.5 million was attributable to a change in the Base Preferred Return Amount of the Alkali Holdings preferred units. Net Loss Attributable to Genesis Energy, L.P. for the three and six months ended June 30, 2021 includes $5.8 million and $10.6 million of adjustments, respectively, of which $4.9 million and $9.0 million, respectively, was allocated to the PIK distributions and $0.9 million and $1.6 million, respectively, was attributable to redemption accretion value adjustments. We elected to pay distributions for the period ended June 30, 2022 in-kind to our Alkali Holdings preferred unitholders.

~~The following table shows the change in our redeemable noncontrolling interest balance from December 31, 2021 to June 30, 2022:~~


~~Balance as of December 31, 2021~~	$	~~259,568~~
~~Issuance of preferred units, net of issuance costs(1)~~	~~5,249~~
~~PIK distribution~~	~~9,993~~
~~Redemption accretion~~	~~1,908~~
~~Tax distributions(1)~~	~~(6,631)~~

~~Adjustment to Base Preferred Return Amount~~	~~18,542~~

~~Redemption of preferred units on May 17, 2022~~	~~(288,629)~~
~~Balance as of June 30, 2022~~	$	—

~~(1)During the period ended June 30, 2022, we issued 5,356 Alkali Holdings preferred units to BXC to satisfy the Company’s obligation to pay tax distributions.~~

Noncontrolling Interests

~~On November 17, 2021, we, through~~We own a ~~subsidiary, sold 36% of the~~64% membership interests in ~~CHOPS for proceeds of approximately $418 million. We retained 64% of the membership interests in CHOPS~~Cameron Highway Oil Pipeline Co. (“CHOPS”) and ~~remain~~are the operator of ~~the CHOPS~~its pipeline and associated ~~assets.~~assets (the “CHOPS pipeline”). We also own an 80% membership interest in Independence Hub, LLC. On April 29, 2022, we entered into an agreement to sell the Independence Hub platform to a producer group in the Gulf of Mexico for gross proceeds of $40 million, of which $8 million, or 20%, is attributable and was paid to our noncontrolling interest holders. For the three and six months ended June 30, 2022, we recognized a gain of $40 million recorded in “Gain on sale of asset” on the Unaudited Condensed Consolidated Statement of Operations, of which $8 million, or 20%, is attributable to our noncontrolling interest holders, as the platform asset sold had no book value at the time of the sale. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our Unaudited Condensed Consolidated Balance Sheets amounts shown as noncontrolling interests in equity.

~~11.~~12. Net Income ~~(Loss)~~ Per Common Unit

Basic net income (loss) per common unit is computed by dividing ~~Net Income (Loss) Attributable~~net income attributable to Genesis Energy, L.P., after considering income attributable to our Class A preferred unitholders, by the weighted average number of common units outstanding.

The dilutive effect of our Class A Convertible Preferred Units is calculated using the if-converted method. Under the if-converted method, the Class A Convertible Preferred Units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

net income (loss) per common unit calculation for the period being presented. ~~Distributions~~The numerator is adjusted for distributions declared in the period, ~~and~~ undeclared distributions that accumulated during the period, ~~are added back to~~and any returns that accumulated in the ~~numerator for purposes of the if-converted calculation.~~period. For the three and six months ended June 30, ~~2022~~2023 and ~~2021,~~2022, the effect of the assumed conversion of all the ~~25,336,778~~outstanding 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~~net income ~~(loss)~~ attributable to Genesis Energy, L.P. and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands):


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Net income (loss) attributable to Genesis Energy, L.P.		$	35,347	$	(41,682)	$	30,097	$	(75,906)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units		(18,684)		(18,684)		(37,368)		(37,368)
Net income attributable to Genesis Energy, L.P.										Net income attributable to Genesis Energy, L.P.	$	49,344	$	35,347	$	47,700	$	30,097
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units										Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(22,910)		(18,684)		(46,912)		(37,368)
Net income (loss) attributable to common unitholders	Net income (loss) attributable to common unitholders	$	16,663	$	(60,366)	$	(7,271)	$	(113,274)	Net income (loss) attributable to common unitholders	$	26,434	$	16,663	$	788	$	(7,271)

Weighted average outstanding units	Weighted average outstanding units	122,579		122,579		122,579		122,579		Weighted average outstanding units	122,579		122,579		122,579		122,579

Basic and diluted net income (loss) per common unit	Basic and diluted net income (loss) per common unit	$	0.14	$	(0.49)	$	(0.06)	$	(0.92)	Basic and diluted net income (loss) per common unit	$	0.22	$	0.14	$	0.01	$	(0.06)

~~12.~~

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13. Business Segment Information

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

•Offshore pipeline transportation, ~~– offshore~~which includes transportation and processing of crude oil and natural gas in the Gulf of Mexico;

•~~Sodium minerals~~Soda and sulfur services –involving trona and trona-based exploring, mining, processing, ~~producing,~~soda ash production, marketing, logistics and selling activities, as well as ~~the~~ processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and ~~the~~ selling of the related by-product, ~~NaHS;~~sodium hydrosulfide (or “NaHS,” commonly pronounced “nash”);

•Onshore facilities and transportation, ~~– terminalling,~~which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum ~~products (primarily fuel oil, asphalt and other heavy refined products);~~products; and

•Marine ~~transportation – marine~~ transportation to provide waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America.

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, net of the effects of our noncontrolling interests, plus our equity in distributable cash generated by our equity investees and unrestricted subsidiaries. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation ~~plan and includes the non-income portion of payments received under our previously owned direct financing lease.~~plan.

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.

2022

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~~GENESIS ENERGY, L.P.~~

~~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			Offshore Pipeline Transportation		Soda and Sulfur Services		Onshore Facilities and Transportation		Marine Transportation		Total
Three Months Ended June 30, 2022
Segment margin (a)		$	118,980	$	71,701	$	11,018	$	17,573	$	219,272
Capital expenditures (b)		$	44,369	$	38,920	$	1,780	$	4,070	$	89,139
Three Months Ended June 30, 2023												Three Months Ended June 30, 2023
Segment Margin(1)												Segment Margin(1)	$	93,300	$	89,255	$	6,305	$	25,758	$	214,618
Capital expenditures(2)												Capital expenditures(2)	$	91,645	$	26,622	$	2,088	$	10,990	$	131,345
Revenues:	Revenues:											Revenues:
External customers	External customers	$	82,085	$	321,192	$	242,131	$	76,317	$	721,725	External customers	$	91,459	$	465,077	$	170,783	$	77,343	$	804,662
Intersegment (c)		—		(2,584)		2,581		3		—
Intersegment(3)												Intersegment(3)	—		(2,222)		2,222		—		—
Total revenues of reportable segments	Total revenues of reportable segments	$	82,085	$	318,608	$	244,712	$	76,320	$	721,725	Total revenues of reportable segments	$	91,459	$	462,855	$	173,005	$	77,343	$	804,662
Three Months Ended June 30, 2021
Segment margin (a)		$	83,106	$	38,194	$	22,368	$	8,468	$	152,136
Capital expenditures (b)		$	19,421	$	80,560	$	2,487	$	11,157	$	113,625
Three Months Ended June 30, 2022												Three Months Ended June 30, 2022
Segment Margin(1)												Segment Margin(1)	$	118,980	$	71,701	$	11,018	$	17,573	$	219,272
Capital expenditures(2)												Capital expenditures(2)	$	44,369	$	38,920	$	1,780	$	4,070	$	89,139
Revenues:	Revenues:											Revenues:
External customers	External customers	$	73,221	$	239,258	$	144,406	$	46,970	$	503,855	External customers	$	82,085	$	321,192	$	242,131	$	76,317	$	721,725
Intersegment (c)		—		(2,171)		1,515		656		—
Intersegment(3)												Intersegment(3)	—		(2,584)		2,581		3		—
Total revenues of reportable segments												Total revenues of reportable segments	$	82,085	$	318,608	$	244,712	$	76,320	$	721,725
Six Months Ended June 30, 2023												Six Months Ended June 30, 2023
Segment Margin(1)												Segment Margin(1)	$	191,238	$	155,362	$	11,695	$	51,452	$	409,747
Capital expenditures(2)												Capital expenditures(2)	$	143,698	$	46,607	$	4,018	$	20,047	$	214,370
Revenues:												Revenues:
External customers												External customers	$	182,854	$	911,983	$	339,868	$	160,569	$	1,595,274
Intersegment(3)												Intersegment(3)	—		(4,480)		4,480		—		—
Total revenues of reportable segments	Total revenues of reportable segments	$	73,221	$	237,087	$	145,921	$	47,626	$	503,855	Total revenues of reportable segments	$	182,854	$	907,503	$	344,348	$	160,569	$	1,595,274
Six Months Ended June 30, 2022	Six Months Ended June 30, 2022											Six Months Ended June 30, 2022
Segment Margin(1)	Segment Margin(1)	$	189,884	$	139,076	$	18,054	$	29,710	$	376,724	Segment Margin(1)	$	189,884	$	139,076	$	18,054	$	29,710	$	376,724
Capital expenditures(2)	Capital expenditures(2)	$	79,810	$	65,246	$	2,517	$	14,129	$	161,702	Capital expenditures(2)	$	79,810	$	65,246	$	2,517	$	14,129	$	161,702
Revenues:	Revenues:											Revenues:
External customers	External customers	$	150,153	$	609,200	$	462,426	$	131,893	$	1,353,672	External customers	$	150,153	$	609,200	$	462,426	$	131,893	$	1,353,672
Intersegment(3)	Intersegment(3)	—		(4,918)		4,717		201		—		Intersegment(3)	—		(4,918)		4,717		201		—
Total revenues of reportable segments	Total revenues of reportable segments	$	150,153	$	604,282	$	467,143	$	132,094	$	1,353,672	Total revenues of reportable segments	$	150,153	$	604,282	$	467,143	$	132,094	$	1,353,672
Six June Months Ended June 30, 2021
Segment Margin(1)		$	167,375	$	81,914	$	43,367	$	15,577	$	308,233
Capital expenditures(2)		$	30,949	$	90,598	$	3,586	$	22,871	$	148,004
Revenues:
External customers		$	137,605	$	468,564	$	332,556	$	86,349	$	1,025,074
Intersegment(3)		—		(4,190)		2,582		1,608		—
Total revenues of reportable segments		$	137,605	$	464,374	$	335,138	$	87,957	$	1,025,074

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

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

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

Total assets by reportable segment were as follows:


	June 30, 2023		December 31, 2022
Offshore pipeline transportation	$	2,370,338	$	2,290,488
Soda and sulfur services	2,560,004		2,358,086
Onshore facilities and transportation	1,021,965		981,354
Marine transportation	650,443		681,231
Other assets	66,709		54,833
Total consolidated assets	$	6,669,459	$	6,365,992

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Total assets by reportable segment were as follows:~~
June 30,
2022 December 31, 2021
Offshore pipeline transportation $ 2,142,264 $ 2,103,140
Sodium minerals and sulfur services 2,195,737 2,132,588
Onshore facilities and transportation 868,779 923,064
Marine transportation 705,265 703,030
Other assets 59,415 43,979
Total consolidated assets $ 5,971,460 $ 5,905,801

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Net income (loss) attributable to Genesis Energy, L.P.		$	35,347	$	(41,682)	$	30,097	$	(75,906)
Net income attributable to Genesis Energy, L.P.										Net income attributable to Genesis Energy, L.P.	$	49,344	$	35,347	$	47,700	$	30,097
Corporate general and administrative expenses	Corporate general and administrative expenses	21,105		12,359		36,826		23,511		Corporate general and administrative expenses	18,487		21,105		34,251		36,826
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	76,277		69,684		149,225		138,681		Depreciation, depletion, amortization and accretion	71,754		76,277		147,689		149,225
Interest expense	Interest expense	55,959		59,169		111,063		116,998		Interest expense	61,623		55,959		122,477		111,063
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)	4,160		7,692		10,734		16,548		Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income(1)	5,867		4,160		12,148		10,734
Other non-cash items(2)		(8,908)		14,683		(12,479)		33,127
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)										Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)	2,888		(8,319)		30,020		(10,212)
Other non-cash items										Other non-cash items	(7,197)		(589)		(9,658)		(2,267)
Distribution from unrestricted subsidiaries not included in income(3)	Distribution from unrestricted subsidiaries not included in income(3)	32,000		17,500		32,000		35,000		Distribution from unrestricted subsidiaries not included in income(3)	—		32,000		—		32,000
Cancellation of debt income(4)	Cancellation of debt income(4)	(4,737)		—		(4,737)		—		Cancellation of debt income(4)	—		(4,737)		—		(4,737)
Loss on extinguishment of debt(5)	Loss on extinguishment of debt(5)	501		—		501		1,627		Loss on extinguishment of debt(5)	3		501		1,812		501
Differences in timing of cash receipts for certain contractual arrangements(6)	Differences in timing of cash receipts for certain contractual arrangements(6)	16,477		6,446		24,707		6,745		Differences in timing of cash receipts for certain contractual arrangements(6)	11,559		16,477		22,134		24,707

Change in provision for leased items no longer in use	Change in provision for leased items no longer in use	(100)		(6)		(531)		598		Change in provision for leased items no longer in use	—		(100)		—		(531)
Redeemable noncontrolling interest redemption value adjustments(7)	Redeemable noncontrolling interest redemption value adjustments(7)	22,620		5,766		30,443		10,557		Redeemable noncontrolling interest redemption value adjustments(7)	—		22,620		—		30,443
Gain on sale of asset, net to our ownership interest(8)	Gain on sale of asset, net to our ownership interest(8)	(32,000)		—		(32,000)		—		Gain on sale of asset, net to our ownership interest(8)	—		(32,000)		—		(32,000)
Income tax expense	Income tax expense	571		525		875		747		Income tax expense	290		571		1,174		875
Total Segment Margin	Total Segment Margin	$	219,272	$	152,136	$	376,724	$	308,233	Total Segment Margin	$	214,618	$	219,272	$	409,747	$	376,724

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

(2)The three and six months ended June 30, 2023 includes unrealized losses of $2.9 million and $30.0 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges). The three and six months ended June 30, 2022 includes unrealized losses of $2.3 million and unrealized gains of $3.8 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized gains of $10.7 million and $6.4 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. The three and six months ended June 30, 2021 includes unrealized losses of $14.3 million and $32.8 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. Refer to ~~Note 15~~ ~~and~~ ~~Note 16~~ ~~for details.~~

(3)The three and six months ended June 30, 2022 include $32.0 million in cash receipts associated with the sale of the Independence Hub platform by our 80% owned unrestricted subsidiary (as defined under our credit agreement), Independence Hub, LLC. The three and six months ended June 30, 2021 include $17.5 million and $35.0 million in cash receipts not included in income associated with principal repayments on our previously owned NEJD pipeline. We received the final principal payment associated with our previously owned NEJD pipeline in the fourth quarter of 2021. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit agreement.

(4)The three and six months ended June 30, 2022 include income associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market of $4.7 million.

(5)The three and six months ended June 30, 2023 includes the transaction costs associated with the tender and redemption of our 2024 Notes, as well as the write-off of the unamortized issuance costs associated with these notes. Refer to Note 10 for details. The three and six months ended June 30, 2022 ~~includes~~include the write-off of the unamortized issuance costs associated with the senior unsecured notes that we repurchased and extinguished during the period. The six months ended June 30, 2021 includes the transaction costs associated with redemption of our 2023 Notes, as well as the write-off of the unamortized issuance costs associated with these notes. Refer to ~~Note 9~~ ~~for details.~~

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

(7)~~Includes~~The three and six months ended June 30, 2022 include PIK distributions and accretion on the redemption feature ~~attributable to each period,~~ and valuation adjustments to the redemption feature as the associated preferred units were redeemed during the second quarter of 2022. Refer to Note 1011 for details.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

(8)On April 29, 2022, we sold our Independence ~~HUB Platform~~Hub platform and recognized a gain on the sale of $40.0 million, of which $32.0 million was attributable to our 80% ownership interest.

~~13.~~

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14. Transactions with Related Parties

Transactions with ANSAC prior to January 1, 2023 were considered transactions with a related party. As discussed in Note 4, on January 1, 2023, ANSAC became a wholly owned subsidiary of Genesis. For comparability purposes, the transactions reflected in the table below for the three and six months ended June 30, 2022 do not include the activity related to ANSAC.

The transactions with related parties were as follows:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Revenues:	Revenues:									Revenues:

Revenues from services and fees to Poseidon(1)	Revenues from services and fees to Poseidon(1)	$	3,860	$	3,242	$	7,098	$	7,028	Revenues from services and fees to Poseidon(1)	$	5,454	$	3,860	$	9,046	$	7,098
Revenues from product sales to ANSAC		97,328		71,329		185,510		139,284

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	$	330	$	330	Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	330	$	330
Charges for services from Poseidon(1)	Charges for services from Poseidon(1)	254		238		509		478		Charges for services from Poseidon(1)	1,755		254		2,037		509
Charges for services from ANSAC		2,340		519		3,185		697

(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~~reflect what we could have ~~expected to obtain~~obtained in an arms-length transaction.

Transactions with Unconsolidated Affiliates

Poseidon

We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement. Currently, that agreement automatically renews annually unless terminated by either party (as defined in the agreement). Our revenues for the three and six months ended June 30, ~~2022~~2023 include ~~$2.4~~$2.5 million and ~~$4.9~~$5.0 million, respectively, of fees we earned through the provision of services under that agreement. Our revenues for the three and six months ended June 30, ~~2021~~2022 include $2.4 million and ~~$4.7~~$4.9 million, respectively, of fees we earned through the provision of services under that agreement. At June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, Poseidon owed us ~~$1.5~~$3.1 million and $2.4 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 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 June 30, 2022, such amount is not material to us.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Net Sales to ANSAC were $97.3 million and $185.5 million, respectively, during the three and six months ended June 30, 2022 and were $71.3 million and $139.3 million, respectively, during the three and six months ended June 30, 2021. The costs charged to us by ANSAC, included in sodium minerals and sulfur services operating costs, were $2.3 million and $3.2 million, respectively, during the three and six months ended June 30, 2022 and were $0.5 million and $0.7 million, respectively, during the three and six months ended June 30, 2021.

~~Receivables from and payables to ANSAC as of June 30, 2022 and December 31, 2021 are as follows:~~

June 30, December 31,
2022 2021
Accounts receivable - trade, net:
ANSAC $ 89,923 $ 64,799
Accounts payable - trade:
ANSAC $ 2,340 $ 116

~~14.~~15. Supplemental Cash Flow Information

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


		Six Months Ended June 30,					Six Months Ended June 30,
		2022		2021			2023		2022
(Increase) decrease in:	(Increase) decrease in:					(Increase) decrease in:
Accounts receivable	Accounts receivable	$	(48,267)	$	(77,785)	Accounts receivable	$	147,999	$	(48,267)
Inventories	Inventories	(11,604)		21,550		Inventories	(20,187)		(11,604)
Deferred charges	Deferred charges	34,022		9,823		Deferred charges	21,076		34,022
Other current assets	Other current assets	(960)		(4,835)		Other current assets	(129)		(960)
Increase (decrease) in:	Increase (decrease) in:					Increase (decrease) in:
Accounts payable	Accounts payable	(3,720)		49,809		Accounts payable	(130,131)		(3,720)
Accrued liabilities	Accrued liabilities	4,299		32,710		Accrued liabilities	(17,671)		4,299
Net changes in components of operating assets and liabilities	Net changes in components of operating assets and liabilities	$	(26,230)	$	31,272	Net changes in components of operating assets and liabilities	$	957	$	(26,230)

Payments of interest and commitment fees were ~~$114.6~~$117.5 million and ~~$78.0~~$114.6 million for the six months ended June 30, ~~2022~~2023 and June 30, ~~2021,~~2022, respectively. The increase in interest payments during 2022 is primarily related to the timing of interest payments on our senior unsecured notes, specifically our 2027 Notes, as we made an interest payment in January 2022. The first interest payment made on our 2027 Notes was in July 2021.

We capitalized interest of ~~$5.9~~$18.3 million and ~~$1.4~~$5.9 million during the six months ended June 30, ~~2022~~2023 and June 30, ~~2021,~~2022, respectively.

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At June 30, ~~2022~~2023 and June 30, ~~2021,~~2022, we had incurred liabilities for fixed and intangible asset additions totaling ~~$35.5~~$64.0 million and ~~$71.5~~$35.5 million, respectively, that had not been paid at the end of the quarter. Therefore, these amounts 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. The amounts as of June 30, ~~2022 principally~~2023 primarily relate to the capital expenditures associated with our GOP (Note 1011) and offshore growth capital projects.

~~15.~~16. Derivatives

~~Commodity Derivatives~~Crude Oil and Petroleum Products Hedges

We have exposure to commodity price changes related to our petroleum inventory and purchase commitments. We utilize derivative instruments (exchange-traded futures, options and swap contracts) to hedge our exposure to ~~commodity prices, primarily of~~ crude oil, fuel oil ~~natural gas~~ and other petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. ~~Most of the petroleum products, including fuel oil that we supply, cannot be hedged with a high degree of effectiveness with exchange-traded derivative contracts; therefore, we do~~

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

not designate derivative contracts utilized to limit our price risk related to petroleum 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 weWe recognize any changes in the fair value of ~~the~~our derivative contracts as increases or decreases in ~~our cost~~“Onshore facilities and transportation product costs” in the Unaudited Condensed Consolidated Statements of ~~sales.~~Operations. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore, we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed.

We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss within “Onshore facilities and transportation ~~costs -~~ product costs” in the Unaudited Condensed Consolidated Statements of Operations.

In accordance with exchange requirements, we fund the margin associated with our exchange-traded commodity derivative contracts. The amount of the margin is adjusted daily based on the fair value of the commodity derivative contracts. Margin requirements are intended to mitigate a party’s exposure to market volatility and counterparty credit risk. We offset fair value amounts recorded for our exchange-traded derivative contracts against required margin funding in “Current Assets - Other” in our Unaudited Condensed Consolidated Balance Sheets.Natural Gas Hedges

~~Additionally, we utilize swap arrangements.~~ Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts, future purchase contracts, and option contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts are used to fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of natural gas derivative contracts as increases or decreases within ~~“Sodium minerals~~“Soda and sulfur services operating costs” in the Unaudited Condensed Consolidated Statements of Operations.

Forward Freight Hedges

ANSAC is exposed to fluctuations in freight rates for vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge future freight rates for forecasted shipments. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of forward freight contracts as increases or decreases within “Soda and sulfur services operating costs” in the Unaudited Condensed Consolidated Statements of Operations.

Bunker Fuel Hedges

ANSAC is exposed to fluctuations in the price of bunker fuel consumed by vessels used to transport soda ash to our international customers. We use exchange-traded or over-the-counter futures, swaps and options to hedge bunker fuel prices for forecasted shipments. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of bunker fuel contracts as increases or decreases within “Soda and sulfur services operating costs” in the Unaudited Condensed Consolidated Statements of Operations.

Rail Fuel Surcharge Hedges

ANSAC enters into rail transport agreements that require us to pay rail fuel surcharges based on changes in the U.S. On-Highway Diesel Fuel Price published by the U.S. Department of Energy (“DOE”). We use exchange-traded or over-the-counter futures, swaps and options to hedge fluctuations in the fuel price. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of bunker fuel contracts as increases or decreases within “Soda and sulfur services operating costs” in the Unaudited Condensed Consolidated Statements of Operations.

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

At June 30, 2022, we had the following outstanding commodity derivative commodity contracts that were entered into to economically hedge inventory, fixed price purchase commitments or forecasted purchases.

Sell (Short)
Contracts Buy (Long)
Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls) 115 —
Weighted average contract price per Bbl $ 117.88 $ —
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls) 122 128
Weighted average contract price per Bbl $ 107.36 $ 107.84
Natural gas swaps:
Contract volumes (10,000 MMBtu) — 230
Weighted average price differential per MMBtu $ — $ 0.003
Natural gas futures:
Contract volumes (10,000 MMBtu) 93 265
Weighted average contract price per MMBtu $ 7.04 $ 4.67
Natural gas options:
Contract volumes (10,000 MMBtu) 84 25
Weighted average premium received/paid $ 0.57 $ 0.05

~~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 the cash margin balance required to maintain our exchange-traded derivative contracts also affect cash flows from operating activities.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following tables reflect the estimated fair value position of our derivatives at June 30, 2022~~Balance Sheet Netting and ~~December 31, 2021:~~

~~Fair Value of Derivative Assets and Liabilities~~

Unaudited Condensed Consolidated Balance Sheets Location Fair Value
June 30,
2022 December 31, 2021
Asset Derivatives:
Natural Gas Swap (undesignated hedge) Current Assets - Other 135 1,867
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized assets Current Assets - Other $ 4,100 $ 310
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets Current Assets - Other (819) (310)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets $ 3,281 $ —
Commodity derivatives - futures (designated hedges):
Gross amount of recognized assets Current Assets - Other $ 1,715 $ 49
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets Current Assets - Other (407) (49)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets $ 1,308 $ —
Liability Derivatives:
Preferred Distribution Rate Reset Election(2)
Other long-term liabilities (76,817) (83,210)
Natural Gas Swap (undesignated hedge) Current Liabilities -Accrued Liabilities (810) (608)
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized liabilities
Current Assets - Other(1)
$ (819) $ (2,380)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other(1)
819 2,380
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets $ — $ —
Commodity derivatives - futures (designated hedges):
Gross amount of recognized liabilities
Current Assets - Other(1)
$ (407) $ (209)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other(1)
407 209
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets $ — $ —

~~(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.~~

Broker Margin Accounts

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset fair value amounts recorded for our exchange-traded derivative ~~assets and liabilities with~~contracts against required margin funding in “Current Assets - Other” in our ~~cash margin balance.~~Unaudited Condensed Consolidated Balance Sheets. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. Margin requirements are intended to mitigate a party’s exposure to market volatility and counterparty credit risk. On a daily basis, our account equity (consisting of the sum of our cash margin balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin.

As of June 30, 2023, we had a net broker receivable of approximately $9.9 million (consisting of initial margin of $7.8 million increased by $2.1 million variation margin). As of December 31, 2022, we had a net broker receivable of approximately ~~$1.4~~$4.0 million (consisting of initial margin of ~~$2.8 million decreased by $1.5 million variation margin). As of December 31, 2021, we had a net broker receivable of approximately $2.9 million (consisting of initial margin of $2.1~~$3.8 million increased by ~~$0.8~~$0.2 million of variation margin). At June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Financial Statement Impacts

Unrealized gains are subtracted from net income (loss) and unrealized losses are added to net income (loss) in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income (loss) in determining cash flows from operating activities. Changes in the cash margin balance required to maintain our exchange-traded derivative contracts also affect cash flows from operating activities.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~Outstanding Derivatives

At June 30, 2023, we had the following outstanding derivative contracts that were entered into to economically hedge inventory, fixed price purchase commitments or forecasted purchases.


	Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls)	245		—
Weighted average contract price per Bbl	$	70.14	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls)	153		141
Weighted average contract price per Bbl	$	71.70	$	72.34
Crude oil basis differentials:
Contract volumes (1,000 Bbls)	60		60
Weighted average contract price per Bbl	$	(0.93)	$	(0.01)
Natural gas swaps:
Contract volumes (10,000 MMBtu)	—		1,555
Weighted average price differential per MMBtu	$	—	$	0.53
Natural gas futures:
Contract volumes (10,000 MMBtu)	243		1,601
Weighted average contract price per MMBtu	$	2.61	$	3.81









Natural gas options:
Contract volumes (10,000 MMBtu)	103		36
Weighted average premium received/paid	$	0.71	$	0.07






Bunker fuel futures:
Contract volumes (metric tons “MT”)	—		45,100
Weighted average price per MT	$	—	$	520.32
DOE diesel options:
Contract volumes (1,000 Gal)	—		1,500
Weighted average premium received/paid	$	—	$	0.26

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Fair Value of Derivative Assets and Liabilities

The following tables reflect the estimated fair value position of our derivatives at June 30, 2023 and December 31, 2022:


	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
		June 30, 2023		December 31, 2022
Asset Derivatives:
Natural Gas Swap (undesignated hedge)	Current Assets - Accounts receivable - trade, net	$	6,136	$	36,844
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other(1)	1,696		1,238
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	(1,696)		(1,238)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—	$	—
Commodity derivatives - futures (designated hedges):
Gross amount of recognized assets	Current Assets - Other(1)	$	401	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	(401)		—
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—	$	—
Liability Derivatives:

Natural Gas Swap (undesignated hedge)	Current Liabilities -Accrued liabilities	$	(5,541)	$	(4,692)
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other(1)	$	(11,008)	$	(11,061)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	11,008		5,217
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—	$	(5,844)
Commodity derivatives - futures (designated hedges):
Gross amount of recognized liabilities	Current Assets - Other(1)	$	(583)	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	583		—
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—	$	—

(1)As noted above, our exchange-traded derivatives are transacted through brokerage accounts and subject to margin requirements. We offset fair value amounts recorded for our exchange-traded derivative contracts against required margin deposits recorded in our Unaudited Condensed Consolidated Balance Sheets under “Current Assets - Other”.

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.~~Sheets. Corresponding changes in fair value are recognized in “Other income (expense)” in our Unaudited Condensed Consolidated Statement of Operations. ~~At June 30, 2022,~~

On the Election Date, the holders of the Class A Convertible Preferred Units elected to reset the rate to 11.24%, the sum of the three-month LIBOR of 3.74% plus 750 basis points. The fair value of this embedded derivative at the time of election was a liability of ~~$76.8~~$101.8 million. As of the Election Date, the feature within the Class A Convertible Preferred Units that required bifurcation no longer existed and we have adjusted the carrying value of the Class A Convertible Preferred Units

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to include the fair value of the previously bifurcated amount at the Election Date. See Note 1011 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 June 30,				Six Months Ended June 30,					Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended June 30,				Six Months Ended June 30,
			2022		2021		2022		2021				2023		2022		2023		2022
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	$	634	$	(1,563)	$	(536)	$	(7,460)	Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs	$	1,388	$	634	$	2,355	$	(536)
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	2,232		(1,779)		8,280		(5,700)		Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, Soda and sulfur services operating costs	(2,141)		2,232		(12,294)		8,280
Total commodity derivatives	Total commodity derivatives		$	2,866	$	(3,342)	$	7,744	$	(13,160)	Total commodity derivatives		$	(753)	$	2,866	$	(9,939)	$	7,744

Natural Gas Swap	Natural Gas Swap	Sodium minerals and sulfur services operating costs	$	(590)	$	30	$	(1,692)	$	(37)	Natural Gas Swap	Soda and sulfur services operating costs	$	(7,599)	$	(590)	$	6,486	$	(1,692)

Preferred Distribution Rate Reset Election	Preferred Distribution Rate Reset Election	Other income (expense)	$	10,651	$	(14,344)	$	6,393	$	(32,782)	Preferred Distribution Rate Reset Election	Other income (expense)	$	—	$	10,651	$	—	$	6,393

~~16.~~17. Fair-Value Measurements

We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value:

(1)Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;

(2)Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and

(3)Level 3 fair values are based on unobservable inputs in which little or no market data exists.

As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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 June 30, ~~2022~~2023 and December 31, ~~2021.~~2022.

June 30, 2022 December 31, 2021
Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Commodity derivatives:
Assets $ 5,815 $ 135 $ — $ 359 $ 1,867 $ —
Liabilities $ (1,226) $ (810) $ — $ (2,589) $ (608) $ —
Preferred Distribution Rate Reset Election $ — $ — $ (76,817) $ — $ — $ (83,210)

~~Rollforward of Level 3 Fair Value Measurements~~

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



~~Balance as of December 31, 2021~~	$	~~(83,210)~~
~~Net gain for the period included in earnings~~	~~6,393~~

~~Balance as of June 30, 2022~~	$	~~(76,817)~~


	June 30, 2023						December 31, 2022
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Commodity derivatives:
Assets	$	2,097	$	6,136	$	—	$	1,238	$	36,844	$	—
Liabilities	$	(11,591)	$	(5,541)	$	—	$	(11,061)	$	(4,692)	$	—

Our commodity and fuel 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 June 30, ~~2022.~~

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, the discount yield (which is adjusted periodically for relevant changes associated with the industry’s credit markets), default probabilities, equity volatility, U.S. Treasury yields and timing estimates which involve management judgment. Our equity volatility rate used to value our embedded derivative feature was 50% at June 30, 2022. 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 an increase in our discount yield compared to the preceding quarter and December 31, 2021, we recorded an unrealized gain of $10.7 million and $6.4 million, respectively, for the three and six months ended June 30, 2022. Due to a decrease in our discount yield compared to the preceding quarters, we recorded an unrealized loss of $14.3 million and $32.8 million, respectively, for the three and six months ended June 30, 2021. These effects are all recorded within “Other income (expense)” on the Unaudited Condensed Consolidated Statements of Operations.2023.

See Note 1516 for additional information on our derivative instruments.

Other Fair Value Measurements

We believe the debt outstanding under our senior secured credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At June 30, ~~2022~~2023 our senior unsecured notes had a carrying value of approximately ~~$2.9~~$3.0 billion and a fair value of approximately ~~$2.6~~$2.9 billion

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compared to a carrying value of $2.9 billion and fair value of approximately ~~$3.0~~$2.7 billion at December 31, ~~2021.~~2022. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement. At June 30, 2023 and December 31, 2022, our Alkali senior secured notes had a carrying value and fair value of $0.4 billion. The fair value of the Alkali senior secured notes is determined based on trade information in the financial market of securities with similar features and is considered a Level 2 fair value measurement.

~~17.~~18. 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.

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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.

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 Income Attributable to Genesis Energy, L.P. of $49.3 million during the three months ended June 30, 2023 (the “2023 Quarter”) compared to Net Income Attributable to Genesis Energy, L.P. of $35.3 million during the three months ended June 30, 2022 (the “2022 Quarter”) ~~compared to Net Loss Attributable to Genesis Energy, L.P. of $41.7 million during the three months ended June 30, 2021 (the “2021 Quarter”)~~.

Net Income Attributable to Genesis Energy, L.P. in the ~~2022~~2023 Quarter was impacted ~~primarily~~ by: (i) an increase in ~~our Segment Margin of $67.1m, inclusive of the $32 million in proceeds received~~operating income associated with ~~the sale of~~ our ~~80% owned Independence Hub platform asset~~operating segments primarily due to increased volumes and activity in our offshore pipeline transportation segment, increased volumes and pricing in our Alkali Business, and higher day rates in our marine transportation segment (see “Results of Operations” below for additional details on the results of our operating segments); and (ii) a decrease in income attributable to our redeemable noncontrolling interests of $22.6 million as the associated Alkali Holdings preferred units were redeemed during the 2022 Quarter.

These increases were partially offset by higher interest expense of $5.7 million in the 2023 Quarter (see “Results of Operations” below for additional details). Additionally the 2022 Quarter included a gain of $40.0 million, or $32.0 million net to our interests, associated with the divestiture of our previously owned Independence Hub platform and an unrealized (non-cash) gain from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $10.7 million in the 2022 Quarter ~~compared to an unrealized (non-cash) loss of $14.3 million during the 2021 Quarter~~ recorded within “Other income (expense)”; and (iii) cancellation of debt income recognized during the 2022 Quarter of $4.7 million associated with the open market repurchase and extinguishment of certain of our senior unsecured notes. These increases during the 2022 Quarter were partially offset by an increase in income attributable to our redeemable noncontrolling interests by $16.9 million and an increase in general and administrative costs by $7.8 million during the 2022 Quarter (see “Other Costs, Interest, and Income Taxes” below for additional discussion regarding general and administrative costs).

Cash flow from operating activities was $157.7 million for the 2023 Quarter compared to $104.0 million for the 2022 ~~Quarter compared to $111.0 million for the 2021~~ Quarter. The ~~decrease~~increase in cash flow from operating activities is primarily attributable to ~~changes in working capital between the two periods offset by~~ an increase in operating income associated with our ~~Segment Margin. See~~ ~~Note 14~~ ~~in our Unaudited Condensed Consolidated Financial Statements for information regarding~~operating segments (as discussed further below) and positive changes into working capital during the ~~2022 Quarter and 2021 Quarter.~~

Available Cash before Reserves (as defined below in “Non-GAAP Financial Measures”) to our common unitholders was $121.2 million for the 2022 Quarter, an increase of $71.6 million, or 145%, from the 2021 Quarter primarily as a result of our increase in Segment Margin discussed in more detail below. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves.

~~Segment Margin (as defined below in “Non-GAAP Financial Measures”) was $219.3 million for the 2022 Quarter, an increase of $67.1 million, or 44%, from the 2021~~2023 Quarter. A more detailed discussion of our segment results and other costs are included below in “Results of Operations”.

Available Cash before Reserves (as defined below in “Non-GAAP Financial Measures”) to our common unitholders was $96.3 million for the 2023 Quarter, a decrease of $24.9 million, or 21%, from the 2022 Quarter primarily as a result of (i) a decrease in Segment Margin of $4.7 million, discussed in more detail below; (ii) an increase in interest expense of $5.7 million (see “Results of Operations” below for additional details); (ii) an increase in cash payments to our Class A Convertible Preferred unitholders of $4.6 million; and (iii) a decrease in income of $4.7 million associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market during the 2022 Quarter.

Segment Margin (as defined below in “Non-GAAP Financial Measures”) was $214.6 million for the 2023 Quarter, a decrease of $4.7 million, or 2%, from the 2022 Quarter. A more detailed discussion of our segment results and other costs are included below in “Results of Operations”. See “Non-GAAP Financial Measures” below for additional information on ~~Available Cash before Reserves and~~ Segment Margin.

Distribution to Unitholders

On May ~~13, 2022,~~15, 2023, we paid a distribution of $0.15 per common unit related to the first quarter of ~~2022.~~2023. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per preferred unit (or $3.7892 on an annualized basis) for each preferred unit held of record. These distributions were paid on May 15, 2023 to unitholders holders of record at the close of business April 28, 2023.

In July ~~2022,~~2023, we declared our quarterly distribution to our common unitholders of $0.15 per unit related to the ~~2022~~2023 Quarter. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of ~~$0.7374~~$0.9473 per Class A

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Convertible Preferred Unit (or ~~$2.9496~~$3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on August ~~12, 2022~~14, 2023 to unitholders of record at the close of business on July ~~29, 2022.~~31, 2023.

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~~Covid-19,~~ Ukraine War 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. The Covid-19 pandemic, including the outbreak of several variants, has caused continued volatility in commodity prices due to, among other things, reduced industrial activity and travel demand, varying worldwide restrictions and the timing of closing and re-opening of economies throughout the last two years. Additionally, the Russian invasion of Ukraine beginning in February 2022 and the ongoing war in Ukraine has caused additional volatility in commodity prices. While we have seen continued recovery in commodity prices since the beginning of the pandemic, primarily due to economies re-opening over time and the reduction in oil and natural gas supply from the war in Ukraine, there is still an element of volatility that we expect to continue at least for the near-term and possibly longer, due to the uncertainty of the pandemic and the war in Ukraine. This volatility could negatively impact future prices for oil, natural gas, petroleum products and industrial products.

~~We will continue to monitor the market environment and will evaluate whether additional 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 could cause our estimates to differ significantly from actual results, including with respect to the duration and severity of the ~~Covid-19 pandemic and~~lasting impacts of the war in ~~Ukraine. In~~Ukraine and the result of any economic recession or depression that has occurred or may occur in the future as a result of or as it relates to changes in governmental policies aimed at addressing inflation, which could cause fluctuations in global economic conditions, including capital and credit markets. We will continue to monitor the current ~~volatile economic~~market environment and to the extent conditions 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.

Although the ultimate impacts of ~~Covid-19 and~~ the war in Ukraine, and fluctuations in global economic conditions, including capital and credit markets, are still unknown at this time, 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 deleveraging our balance sheet as further explained in “Liquidity and Capital Resources”.

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Results of Operations

Revenues and Costs and Expenses

Our revenues for the ~~2022~~2023 Quarter increased ~~$217.9~~$82.9 million, or ~~43%~~11%, from the ~~2021~~2022 Quarter and our total costs and expenses (excluding the gain on sale of assets) as presented on the Unaudited Condensed Consolidated Statements of Operations increased ~~$186.8~~$36.7 million, or ~~39%~~6%, between the two ~~periods.~~periods with an overall net increase (excluding the gain on sale of assets) to operating income of $46.2 million. The increase in our operating income during the ~~2022~~2023 Quarter is primarily ~~driven by higher export~~due to the increased volumes in our offshore pipeline transportation segment, increased volumes and pricing ~~and corresponding revenues~~ in our Alkali Business, ~~which is included within our sodium mineral and sulfur services segment,~~ and higher ~~revenues~~day rates in our ~~offshore~~marine transportation segment. ~~These increases are partially offset by higher general and administrative costs due to increased transaction costs and higher~~See further discussion below under “Segment Margin” regarding the activity in our individual operating segments. Additionally, we had lower depreciation, depletion, and amortization expense ~~during~~and general and administrative costs in the 2023 Quarter compared to the 2022 Quarter (see “Other Costs, Interest, and Income Taxes” below for additional discussion).

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil in our crude oil marketing business, which is included in our onshore facilities and transportation segment, and revenues and costs associated with our Alkali Business, which is included in our ~~sodium minerals~~soda and sulfur services segment. 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”) ~~increased~~decreased to $73.54 per barrel in the 2023 Quarter, as compared to $108.83 per barrel in the 2022 ~~Quarter, as compared to $66.07 per barrel in the 2021~~ Quarter. 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 ~~loss~~income (loss) 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~~volumes sold. We sell our products to an industry-diverse and worldwide customer base. Our ~~selling~~sales prices are contracted at various times throughout the year and for different durations. Our ~~selling~~sales prices for volumes sold internationally ~~and through ANSAC~~ are contracted for the current year either annually in the prior year or periodically throughout the current year (often quarterly), and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. The majority of our volumes sold internationally are sold through the American Natural Soda Ash Corporation (“ANSAC”), which became a wholly owned subsidiary of our Alkali Business on January 1, 2023 as we became the sole member of it at that time. ANSAC promotes export sales of U.S. produced soda ash utilizing its logistical asset and marketing capabilities. During the three and six months ended June 30, 2023, in addition to the volumes supplied by our operations and sold by ANSAC, ANSAC continued to receive a level of soda ash supply from certain former members to sell internationally, which is expected to continue in some capacity for at least the next several years. As a result of consolidating the results of ANSAC beginning on January 1, 2023, the sale of the soda ash volumes by ANSAC that were supplied by non-members are included in our consolidated results and have a proportionate effect to our revenues and costs, with little to no direct impact to our reported Segment Margin, Net income (loss) and Available Cash before Reserves. We will continue to report the sales volumes of soda ash included in the operating results table for our soda and sulfur services segment shown below as we have historically reported them for comparability purposes and due to the minimal impact these incremental sales volumes from ANSAC have on our reported Segment Margin, Net income (loss) and Available Cash before Reserves. 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, economic growth, and ~~economic growth.~~our ability to produce soda ash. Positive or negative changes to our revenue, through fluctuations in sales volumes or ~~selling~~sales prices, can have a direct impact to Segment Margin, Net income (loss) and Available Cash before Reserves as these fluctuations ~~may~~ have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, some 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 ~~2022~~2023 Quarter, ~~as noted above,~~ we had positive effects to our revenues (with a lesser impact to costs) relative to the ~~2021~~2022 Quarter due to increased sales volumes and favorable ~~ANSAC~~ pricing on our domestic and export tons. For additional information, see our segment-by-segment analysis below.

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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 a billion dollars) to develop large reservoir, long-lived crude oil and natural gas properties; (ii) our sulfur services business, which we believe is one of the largest producers and marketers (based on tons produced) of NaHS in North and South America; and (iii) our 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 ~~over 95% of~~approximately 98% of the volumes transported on our onshore crude pipelines, and refiners contracted for approximately 90% of the revenues from our marine ~~inland barges~~transportation segment during the ~~2022~~2023 Quarter, 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.~~Coast. 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

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volatile commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our Net income (loss), 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~~soda 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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(in thousands)				(in thousands)					(in thousands)				(in thousands)
Offshore pipeline transportation	Offshore pipeline transportation	$	118,980	$	83,106	$	189,884	$	167,375	Offshore pipeline transportation	$	93,300	$	118,980	$	191,238	$	189,884
Sodium minerals and sulfur services		71,701		38,194		139,076		81,914
Soda and sulfur services										Soda and sulfur services	89,255		71,701		155,362		139,076
Onshore facilities and transportation	Onshore facilities and transportation	11,018		22,368		18,054		43,367		Onshore facilities and transportation	6,305		11,018		11,695		18,054
Marine transportation	Marine transportation	17,573		8,468		29,710		15,577		Marine transportation	25,758		17,573		51,452		29,710
Total Segment Margin	Total Segment Margin	$	219,272	$	152,136	$	376,724	$	308,233	Total Segment Margin	$	214,618	$	219,272	$	409,747	$	376,724

We define Segment Margin as revenues less product costs, operating expenses and segment general and administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable Select Items (defined below). 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 Net Income ~~(Loss)~~ Attributable to Genesis Energy, L.P. to total Segment Margin for the periods presented is as follows:


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Net Income (Loss) Attributable to Genesis Energy, L.P.		$	35,347	$	(41,682)	$	30,097	$	(75,906)
Net Income Attributable to Genesis Energy, L.P.										Net Income Attributable to Genesis Energy, L.P.	$	49,344	$	35,347	$	47,700	$	30,097
Corporate general and administrative expenses	Corporate general and administrative expenses	21,105		12,359		36,826		23,511		Corporate general and administrative expenses	18,487		21,105		34,251		36,826
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	76,277		69,684		149,225		138,681		Depreciation, depletion, amortization and accretion	71,754		76,277		147,689		149,225
Interest expense	Interest expense	55,959		59,169		111,063		116,998		Interest expense	61,623		55,959		122,477		111,063
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)	4,160		7,692		10,734		16,548		Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income(1)	5,867		4,160		12,148		10,734
Other non-cash items(2)		(8,908)		14,683		(12,479)		33,127
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)										Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)	2,888		(8,319)		30,020		(10,212)
Other non-cash items										Other non-cash items	(7,197)		(589)		(9,658)		(2,267)
Distributions from unrestricted subsidiaries not included in income(3)	Distributions from unrestricted subsidiaries not included in income(3)	32,000		17,500		32,000		35,000		Distributions from unrestricted subsidiaries not included in income(3)	—		32,000		—		32,000
Cancellation of debt income(4)										Cancellation of debt income(4)	—		(4,737)		—		(4,737)
Loss on debt extinguishment(5)										Loss on debt extinguishment(5)	3		501		1,812		501
Differences in timing of cash receipts for certain contractual arrangements(6)										Differences in timing of cash receipts for certain contractual arrangements(6)	11,559		16,477		22,134		24,707

Change in provision for leased items no longer in use	Change in provision for leased items no longer in use	(100)		(6)		(531)		598		Change in provision for leased items no longer in use	—		(100)		—		(531)
Differences in timing of cash receipts for certain contractual arrangements(4)		16,477		6,446		24,707		6,745

Cancellation of debt income(5)		(4,737)		—		(4,737)		—
Loss on debt extinguishment(6)		501		—		501		1,627

Redeemable noncontrolling interest redemption value adjustments(7)	Redeemable noncontrolling interest redemption value adjustments(7)	22,620		5,766		30,443		10,557		Redeemable noncontrolling interest redemption value adjustments(7)	—		22,620		—		30,443
Gain on sale of asset, net to our ownership interest(8)	Gain on sale of asset, net to our ownership interest(8)	(32,000)		—		(32,000)		—		Gain on sale of asset, net to our ownership interest(8)	—		(32,000)		—		(32,000)
Income tax expense	Income tax expense	571		525		875		747		Income tax expense	290		571		1,174		875
Total Segment Margin	Total Segment Margin	$	219,272	$	152,136	$	376,724	$	308,233	Total Segment Margin	$	214,618	$	219,272	$	409,747	$	376,724

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

(2)The three and six months ended June 30, 2023 includes unrealized losses of $2.9 million and $30.0 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges). The three and six months ended June 30, 2022 ~~include~~includes unrealized losses of $2.3 million and unrealized gains of $3.8 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges) and unrealized gains of $10.7 million and $6.4 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. The three and six months ended June 30, 2021 includes unrealized losses of $14.3 million and $32.8 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.

(4)The three and six months ended June 30, ~~2021~~2022 include ~~$17.5 million and $35.0 million in cash receipts not included in~~ income associated with ~~principal repayments~~the repurchase and extinguishment of certain of our senior unsecured notes on ~~our previously owned NEJD pipeline. We received~~ the ~~final principal payment~~open market of $4.7 million.

(5)The three and six months ended June 30, 2023 include the transaction costs associated with the tender and redemption of our ~~previously owned NEJD pipeline in~~2024 Notes, as well as the ~~fourth quarter~~write-off of ~~2021. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit agreement.~~the unamortized issuance costs associated with these notes. The three and six months ended June 30, 2022 include the write-off of the unamortized issuance costs associated with the senior unsecured notes that we repurchased and extinguished during the period.

~~(4)~~(6)Includes the difference in timing of cash receipts from or billings to 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)~~(7)The three and six months ended June 30, 2022 include ~~income associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market of $4.7 million.~~

~~(6)~~The three and six months ended June 30, 2022 include the write-off of the unamortized issuance costs associated with the senior unsecured notes that we repurchased and extinguished during the period. The six months ended June 30, 2021 include the transaction costs associated with redemption of our 2023 Notes, as well as the write-off of the unamortized issuance costs associated with these notes.

~~(7)Includes~~ PIK distributions and accretion on the redemption feature ~~attributable to each period,~~ and valuation adjustments to the redemption feature as the associated preferred units were redeemed during the ~~2022 Quarter.~~second quarter of 2022.

(8)On April 29, 2022, we sold our Independence ~~HUB~~Hub platform and recognized a gain on the sale of $40.0 million, of which $32.0 million was attributable to our 80% ownership interest.

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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 June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(in thousands)				(in thousands)					(in thousands)				(in thousands)
Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues	Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues	$	76,056	$	70,153	$	136,924	$	132,815	Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues	$	76,152	$	76,056	$	154,167	$	136,924
Offshore natural gas pipeline revenue, excluding non-cash revenues	Offshore natural gas pipeline revenue, excluding non-cash revenues	13,439		10,567		22,508		20,964		Offshore natural gas pipeline revenue, excluding non-cash revenues	15,367		13,439		29,423		22,508
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses	Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses	(20,247)		(19,328)		(37,523)		(37,334)		Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses	(18,272)		(20,247)		(35,814)		(37,523)
Distributions from unrestricted subsidiaries(1)	Distributions from unrestricted subsidiaries(1)	32,000		—		32,000		—		Distributions from unrestricted subsidiaries(1)	—		32,000		—		32,000
Distributions from equity investments(2)	Distributions from equity investments(2)	17,732		21,714		35,975		50,930		Distributions from equity investments(2)	20,053		17,732		43,462		35,975
Offshore pipeline transportation Segment Margin	Offshore pipeline transportation Segment Margin	$	118,980	$	83,106	$	189,884	$	167,375	Offshore pipeline transportation Segment Margin	$	93,300	$	118,980	$	191,238	$	189,884

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 Bbls/day unless otherwise noted):										Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS	CHOPS	220,498		204,963		198,313		160,940		CHOPS	258,939		220,498		246,606		198,313
Poseidon	Poseidon	262,800		265,359		251,872		302,180		Poseidon	288,384		262,800		301,698		251,872
Odyssey	Odyssey	100,237		125,170		98,742		131,771		Odyssey	59,924		100,237		62,774		98,742
GOPL(3)	GOPL(3)	8,579		8,646		6,777		7,716		GOPL(3)	2,380		8,579		2,185		6,777
Total crude oil offshore pipelines	Total crude oil offshore pipelines	592,114		604,138		555,704		602,607		Total crude oil offshore pipelines	609,627		592,114		613,263		555,704

Natural gas transportation volumes (MMBtus/day)	Natural gas transportation volumes (MMBtus/day)	384,330		347,123		328,423		336,456		Natural gas transportation volumes (MMBtus/day)	397,801		384,330		392,529		328,423

Volumetric Data net to our ownership interest(4):	Volumetric Data net to our ownership interest(4):									Volumetric Data net to our ownership interest(4):
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS(5)		141,119		204,963		126,920		160,940
Crude oil pipelines (average Bbls/day unless otherwise noted):										Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS										CHOPS	165,721		141,119		157,828		126,920
Poseidon	Poseidon	168,192		169,830		161,198		193,395		Poseidon	184,566		168,192		193,087		161,198
Odyssey	Odyssey	29,069		36,299		28,635		38,214		Odyssey	17,378		29,069		18,204		28,635
GOPL(3)	GOPL(3)	8,579		8,646		6,777		7,716		GOPL(3)	2,380		8,579		2,185		6,777
Total crude oil offshore pipelines	Total crude oil offshore pipelines	346,959		419,738		323,530		400,265		Total crude oil offshore pipelines	370,045		346,959		371,304		323,530

Natural gas transportation volumes (MMBtus/day)	Natural gas transportation volumes (MMBtus/day)	119,376		108,695		105,625		105,614		Natural gas transportation volumes (MMBtus/day)	115,866		119,376		111,434		105,625

(1)Offshore pipeline transportation Segment Margin for the three and six months ended June 30, 2022 includes distributions received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32.0 million associated with the sale of our 80% owned platform asset.

(2)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in ~~2022~~2023 and ~~2021,~~2022, respectively.

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

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

~~(5)~~On November 17, 2021, we divested a 36% minority interest in our CHOPS pipeline. The volumes for the three and six months ended June 30, 2022 represent our 64% net ownership and the volumes presented for the three and six months ended June 30, 2021 represent our 100% ownership during that period.

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

Offshore pipeline transportation Segment Margin for the ~~2022~~2023 Quarter ~~increased $35.9~~decreased $25.7 million, or ~~43%~~22%, from the ~~2021~~2022 Quarter primarily ~~as a result of: (i) distributions~~due to the distribution received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32.0 million in the 2022 Quarter from the sale of its platform asset. Excluding this distribution, segment margin in our offshore pipeline transportation segment increased during the 2023 Quarter as a result of higher overall crude oil and natural gas volumes, which more than offset the additional producer downtime we experienced during the period, most of which was

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~~$32 million for the sale~~planned, that impacted volumes on one of our ~~80% owned platform asset; (ii) increased crude oil~~deepwater lateral pipelines and ~~natural gas activity and associated revenues~~further downstream on our Poseidon pipeline. The increase in our overall volumes during the ~~2022~~2023 Quarter ~~primarily as~~is a result of ~~first oil being achieved on April 12, 2022 at~~ the King’s Quay ~~floating production system; and (iii) contractual minimum volume commitments~~Floating Production System (“~~MVCs”~~FPS”) ~~at King’s Quay and Argos that began~~, which achieved first oil in the 2022 Quarter, and ~~contributed~~has since ramped up production to ~~our reported Segment Margin.~~

a level of approximately 130,000 barrels of oil equivalent per day in the 2023 Quarter, and the Argos FPS, which achieved first oil in April 2023. The King’s Quay ~~floating production system,~~FPS, which is supporting the Khaleesi, Mormont and Samurai field developments, is life-of-lease dedicated to our 100% owned crude oil and natural gas lateral pipelines and further downstream to our 64% owned Poseidon and CHOPS crude oil systems or our 25.67% owned Nautilus natural gas system for ultimate delivery to shore. ~~While~~The Argos FPS supports the 14 wells pre-drilled and completed at BP’s operated Mad Dog 2 field development, of which 3 wells began producing in the 2023 Quarter, with 100% of the volumes ~~during the 2022 Quarter~~flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore. We expect to continue to benefit from King’s Quay ~~were below the contracted MVCs, we were still able to recognize our MVCs in Segment Margin. We expect King’s Quay to ramp up to its design capacity~~FPS and Argos FPS volumes throughout 2023 and over ~~the remainder of the year as the operator brings the remaining wells on-line. In addition, we have contractual MVCs that began in the 2022 Quarter associated with the Argos floating~~their anticipated production system (which supports the Mad Dog 2 development), and are included in our reported Segment Margin during the 2022 Quarter. Argos is anticipated to have first oil in the second half of 2022. These increases more than offset the effects from our decrease in ownership of CHOPS, as we sold a 36% minority interest on November 17, 2021.profiles.

Six Months Ended June 30, ~~2022~~2023 Compared with Six Months Ended June 30, ~~2021~~2022

Offshore pipeline transportation Segment Margin for the first six months of ~~2022~~2023 increased ~~$22.5~~$1.4 million, or ~~13%~~1%, from the first six months of ~~2021~~2022 primarily due ~~to: (i)~~to increased crude oil and natural gas activity, primarily from volumes associated with the King’s Quay FPS, as first oil was achieved in the 2022 Quarter. The 2023 period benefited from six months of volumes from King’s Quay, including its ramp in production to a level of approximately 130,000 barrels of oil equivalent per day in the 2023 Quarter. Additionally, the first six months of 2023 benefited from volumes at the Argos FPS, which achieved first oil in April 2023. These increases were offset by distributions received from one of our unrestricted subsidiaries, Independence Hub LLC, of $32 million ~~for~~from the sale of ~~our 80% owned~~its platform asset and (ii) increased crude oil and natural gas activity, primarily from first oil achievement at King’s Quay on April 12, 2022, as well as MVCs associated with both King’s Quay and Argos as discussed above. These increases were partially offset by an increased level of downtime during 2022, specifically in the first quarter, that was primarily a result of unplanned operational maintenance associated with one of our lateral pipelines that also impacted volumes on our main pipeline downstream of it, which was remedied in the first quarter of 2022, and incremental producer downtime. Lastly, the 2022 period was impacted, relative to the 2021 period, by our decrease in ownership of CHOPS, as we sold a 36% minority interest on November 17, 2021.2022.

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~~Sodium Minerals~~Soda and Sulfur Services Segment

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Volumes sold:	Volumes sold:									Volumes sold:
NaHS volumes (Dry short tons “DST”)	NaHS volumes (Dry short tons “DST”)	35,633		28,052		67,802		56,854		NaHS volumes (Dry short tons “DST”)	26,086		35,633		54,176		67,802
Soda Ash volumes (short tons sold)	Soda Ash volumes (short tons sold)	772,141		772,132		1,516,929		1,534,952		Soda Ash volumes (short tons sold)	852,019		772,141		1,556,831		1,516,929
NaOH (caustic soda) volumes (DST)	NaOH (caustic soda) volumes (DST)	22,073		21,124		42,797		41,386		NaOH (caustic soda) volumes (DST)	20,346		22,073		40,522		42,797

Revenues (in thousands):	Revenues (in thousands):									Revenues (in thousands):
NaHS revenues, excluding non-cash revenues	NaHS revenues, excluding non-cash revenues	$	52,184	$	30,134	$	93,812	$	60,270	NaHS revenues, excluding non-cash revenues	$	38,011	$	52,184	$	80,208	$	93,812
NaOH (caustic soda) revenues	NaOH (caustic soda) revenues	16,666		9,799		30,677		18,206		NaOH (caustic soda) revenues	17,334		16,666		35,795		30,677
Revenues associated with Alkali Business(1)	Revenues associated with Alkali Business(1)	219,032		173,779		422,691		341,103		Revenues associated with Alkali Business(1)	385,891		219,032		748,830		422,691
Other revenues	Other revenues	2,572		893		4,453		1,823		Other revenues	1,288		2,572		2,773		4,453
Total external segment revenues, excluding non-cash revenues~~(1)~~	Total external segment revenues, excluding non-cash revenues~~(1)~~	$	290,454	$	214,605	$	551,633	$	421,402	Total external segment revenues, excluding non-cash revenues~~(1)~~	$	442,524	$	290,454	$	867,606	$	551,633

Segment Margin (in thousands)	Segment Margin (in thousands)	$	71,701	$	38,194	$	139,076	$	81,914	Segment Margin (in thousands)	$	89,255	$	71,701	$	155,362	$	139,076

Average index price for NaOH per DST(2)	Average index price for NaOH per DST(2)	$	1,077	$	755	$	1,024	$	702	Average index price for NaOH per DST(2)	$	1,123	$	1,077	$	1,168	$	1,024

(1)~~Totals are for external~~See discussion above in “Results of Operations — Revenues and Costs and Expenses” regarding revenues ~~and costs prior to intercompany elimination upon consolidation.~~associated with our Alkali Business.

(2)Source: IHS Chemical.

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

~~Sodium minerals~~Soda and sulfur services Segment Margin for the ~~2022~~2023 Quarter increased ~~$33.5~~$17.6 million, or ~~88%~~24%, from the ~~2021~~2022 Quarter primarily due to higher domestic and export pricing and an increase in ~~our Alkali Business and increased~~sales volumes ~~and pricing~~ in our refinery services business. In our Alkali Business, we have continued to see strong demand improvement and growth as a result of the global economic recovery and the continued application of soda ash in everyday end use products and in products such as solar panels and lithium batteries that are expected to play a large role in the anticipated energy transition. This continued demand, combined with flat or even slightly declining supply of natural soda ash in the near term, has tightened the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during the 2022 Quarter from our Alkali Business. We ~~expect~~successfully restarted our original Granger production facility on January 1, 2023 and, during the 2023 Quarter, ramped up the production to ~~continue to see this favorable price environment throughout 2022 and until there are significant changes to the supply level entering the market. To take advantage~~its original nameplate capacity of ~~the existing market conditions,~~approximately 500,000 tons on an annual basis. Additionally, we ~~made the decision and~~ are still on schedule to ~~re-start~~complete our ~~original Granger production facility and its roughly 500,000 tons of annual production in the first quarter of 2023 in advance of the completion of the~~ Granger Optimization Project (“GOP”), in the second half of 2023, which represents an incremental 750,000 tons of annual production that we anticipate to ramp up to. As noted above, the 2023 Quarter benefited from higher domestic and ~~is expected~~export pricing as compared to ~~have first production~~the 2022 Quarter as we continued to see a balanced supply and demand market. While we continue to expect our weighted average sales price for 2023 to exceed our weighted average sales price in 2022, we are beginning to see a level of volatility in pricing as a result of a slower than anticipated re-opening of China’s economy combined with the ~~third quarter~~anticipation of ~~2023.~~new global supply entering the market. In our refinery services business, we ~~had~~experienced lower than expected production due to unplanned operational and weather-related outages at several of our host refineries during the 2023 Quarter. In addition, a host refinery partially converted their facility into a renewable diesel facility, which was completed in the fourth quarter of 2022. This partial conversion resulted in lower NaHS production and sales volumes during the period when compared to the 2022 Quarter, which also experienced higher NaHS sales volumes from our mining customers, primarily in South America. Additionally, during the 2022 Quarter, we experienced an increase in NaHS sales volumes due to our ability to leverage our multi-faceted supply and terminal sites to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges.

Table of Contents

Six Months Ended June 30, 2023 Compared with Six Months Ended June 30, 2022

Soda and sulfur services Segment Margin for the ~~corresponding~~first six months of 2023 increased $16.3 million, or 12%, from the first six months of 2022 primarily due to higher domestic and export pricing ~~of these~~and an increase in sales volumes in our Alkali Business. We successfully restarted our original Granger production facility on January 1, 2023 and, during the 2023 Quarter, ramped up the production to its original nameplate capacity of approximately 500,000 tons on an annual basis as we exited the 2023 Quarter. This increase was partially offset by the lower production and ultimate sales of soda ash during the first quarter of 2023 from the extreme winter weather conditions that impacted our operations and certain supply chain functions, most notably the rail service in and out of the Green River Basin. In our refinery services business, we experienced lower than expected production due to multiple factors, including a slower than expected ramp up in production from the completion of a major turnaround at one of our largest host refineries in the fourth quarter of 2022, unplanned operational and weather-related outages at several of our host refineries during the 2023 Quarter, and lower production from a host refinery that partially converted their facility into a renewable diesel facility in the fourth quarter of 2022. In addition, during the first six months of 2022, we experienced robust NaHS sales volumes and prices due to an increase in demand from our mining customers, primarily in South America, ~~as a result of the continued global economic recovery~~ and ~~the use of NaHS in products, such as copper, that are a key part of the anticipated energy transition. Additionally, during the 2022 Quarter, we were able~~due to our ability to leverage our multi-faceted supply and terminal sites in our refinery services business to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges.

~~Table of Contents~~

~~Six Months Ended June 30, 2022 Compared with Six Months Ended June 30, 2021~~

Sodium minerals and sulfur services Segment Margin for the first six months of 2022 increased $57.2 million, or 70%, from the first six months of 2021 primarily due to higher export pricing in our Alkali business and increased volumes and pricing in our refinery services business. In our Alkali Business, we have continued to see strong demand improvement and growth as a result of the global economic recovery and the continued application of soda ash in everyday end use products and in products such as solar panels and lithium batteries that are expected to play a large role in the anticipated energy transition. This continued demand, combined with flat or even slightly declining supply of natural soda ash in the near term, has tightened the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during 2022 from our Alkali Business. In our refinery services business, we had an increase in NaHS sales volumes and the corresponding pricing of these sales volumes in 2022 due to an increase in demand from our mining and pulp and paper customers as a result of the continued global economic recovery and the use of NaHS in products, such as copper, that are a key part of the anticipated energy transition.

Onshore Facilities and Transportation Segment

Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, trucks 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 unloading facilities operating primarily within the U.S. Gulf Coast crude oil market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and bulk purchased crude ~~oil, as well as purchased and sold refined products.~~oil. Through these assets we offer our customers a full suite of services, including the ~~following:~~following as of June 30, 2023:

•facilitating the transportation of crude oil from producers to refineries and from our terminals, as well as those owned ~~and~~by third ~~party terminals~~parties, to refiners via pipelines;

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

•~~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.~~markets; and

•unloading railcars at our crude-by-rail terminals.

We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

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.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(in thousands)				(in thousands)					(in thousands)				(in thousands)
Gathering, marketing, and logistics revenue	Gathering, marketing, and logistics revenue	$	234,777	$	136,148	$	448,421	$	314,710	Gathering, marketing, and logistics revenue	$	164,966	$	234,777	$	328,986	$	448,421
Crude oil pipeline tariffs and revenues	Crude oil pipeline tariffs and revenues	8,025		8,902		15,359		18,877		Crude oil pipeline tariffs and revenues	6,431		8,025		12,517		15,359
Distributions from unrestricted subsidiaries not included in income(1)		—		17,500		—		35,000
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions		(217,711)		(124,383)		(417,716)		(286,367)

Crude oil and products costs, excluding unrealized gains and losses from derivative transactions										Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(149,463)		(217,711)		(298,396)		(417,716)
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	(16,573)		(15,431)		(32,342)		(30,697)		Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	(17,473)		(16,573)		(34,516)		(32,342)
Other	Other	2,500		(368)		4,332		(8,156)		Other	1,844		2,500		3,104		4,332
Segment Margin	Segment Margin	$	11,018	$	22,368	$	18,054	$	43,367	Segment Margin	$	6,305	$	11,018	$	11,695	$	18,054

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~~(2)~~	Texas~~(2)~~	93,739		84,551		81,604		58,800		Texas~~(2)~~	66,505		93,739		65,278		81,604
Jay	Jay	6,663		7,933		6,788		8,356		Jay	5,952		6,663		5,481		6,788
Mississippi	Mississippi	6,233		5,327		5,989		5,213		Mississippi	4,737		6,233		4,872		5,989
Louisiana~~(3)~~(1)	Louisiana~~(3)~~(1)	51,422		46,319		41,457		54,821		Louisiana~~(3)~~(1)	70,816		119,254		75,860		90,676

Onshore crude oil pipelines total	Onshore crude oil pipelines total	158,057		144,130		135,838		127,190		Onshore crude oil pipelines total	148,010		225,889		151,491		185,057

Crude oil and petroleum products sales:
Total crude oil and petroleum products sales		22,060		20,653		22,968		26,028
Crude oil and petroleum products sales										Crude oil and petroleum products sales	23,029		22,060		22,652		22,968
Rail unload volumes	Rail unload volumes	25,680		3,556		14,156		21,803		Rail unload volumes	—		25,680		—		14,156

(1)The three and six months ended June 30, 2021 includes total cash payments received of $17.5 million and $35.0 million, respectively, not included in income from the NEJD pipeline. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our senior secured credit agreement.

~~(2)~~Our Texas pipeline and infrastructure is a destination point for many pipeline systems in the Gulf of Mexico, including the CHOPS pipeline. Volumes during the six months ended June 30, 2021 were impacted as a result of the CHOPS pipeline being out of service from August 26, 2020 to February 4, 2021.

~~(3)~~Total daily ~~volume~~volumes for the three and six months ended June 30, ~~2022 includes 29,469~~2023 include 29,891 and ~~29,097 barrels per~~ 30,703 Bbls/day, respectively, of intermediate refined products and 40,925 and 44,898 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily ~~volume~~volumes for the three and six months ended June 30, ~~2021 includes 39,875~~2022 include 29,469 and ~~32,397 barrels per~~ 29,097 Bbls/day, respectively, of intermediate refined products and 67,832 and 49,219 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

Onshore facilities and transportation Segment Margin for the ~~2022~~2023 Quarter decreased ~~$11.4,~~$4.7 million, or ~~51%~~43%, from the ~~2021 Quarter. This decrease is~~2022 Quarter primarily due to ~~the 2021 Quarter including cash receipts of $17.5 million associated with our previously owned NEJD pipeline. The last principal payment associated with our previously owned NEJD pipeline was received~~a decrease in ~~the fourth quarter of 2021. This decrease was partially offset by higher~~ rail unload ~~and pipeline volumes, primarily associated with our assets in the Baton Rouge corridor. Our~~volumes. The 2022 Quarter had an increase in rail volumes ~~was~~as a result of our main customer sourcing volumes to replace international volumes that were impacted by certain geopolitical events ~~and we expect these~~in the period. The rail unload volumes during the 2022 Quarter also increased our Louisiana pipeline volumes in the respective period as the crude oil unloaded was subsequently transported on our Louisiana pipeline to ~~continue into the third quarter of 2022. Additionally, we had higher~~our customer’s refinery complex. In addition, there was a decrease in volumes on our Texas pipeline ~~which is a destination point for various grades of crude oil produced in~~system during the ~~Gulf of Mexico including those transported on our 64% owned CHOPS pipeline.~~

~~Table of Contents~~

2023 Quarter.

Six Months Ended June 30, ~~2022~~2023 Compared with Six Months Ended June 30, ~~2021~~2022

Onshore facilities and transportation Segment Margin for the first six months of ~~2022~~2023 decreased ~~$25.3~~$6.4 million, or ~~58% primarily due to~~35%, from the first six months of ~~2021 including cash receipts of approximately $35 million associated with our previously owned NEJD pipeline.~~2022. This decrease ~~was partially offset by higher contributions~~is primarily due to ~~Segment Margin from~~a decrease in activity on our ~~pipeline, rail, and terminal assets in the~~ Baton Rouge ~~corridor. While~~corridor assets, specifically our rail unload and pipeline volumes as discussed above, and a decrease in volumes on our Texas pipeline system during the ~~volumes were lower during 2022 compared to 2021, our main customer utilized prepaid transportation credits during 2021, which were fully utilized by the end~~first six months of ~~2021.~~2023.

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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 capacity ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,						Six Months Ended June 30,
		2022			2021			2022			2021				2023			2022			2023			2022
Revenues (in thousands):	Revenues (in thousands):													Revenues (in thousands):
Inland freight revenues	Inland freight revenues	$	26,196		$	18,231		$	47,232		$	35,746		Inland freight revenues	$	31,890		$	26,196		$	63,093		$	47,232
Offshore freight revenues	Offshore freight revenues	23,953			16,504			42,891			31,030			Offshore freight revenues	26,876			23,953			53,882			42,891
Other rebill revenues(1)	Other rebill revenues(1)	26,171			12,891			41,971			21,181			Other rebill revenues(1)	18,577			26,171			43,594			41,971
Total segment revenues	Total segment revenues	$	76,320		$	47,626		$	132,094		$	87,957		Total segment revenues	$	77,343		$	76,320		$	160,569		$	132,094

Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (in thousands)	Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (in thousands)	$	58,747		$	39,158		$	102,384		$	72,380		Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (in thousands)	$	51,585		$	58,747		$	109,117		$	102,384

Segment Margin (in thousands)	Segment Margin (in thousands)	$	17,573		$	8,468		$	29,710		$	15,577		Segment Margin (in thousands)	$	25,758		$	17,573		$	51,452		$	29,710

Fleet Utilization:(2)	Fleet Utilization:(2)													Fleet Utilization:(2)
Inland Barge Utilization	Inland Barge Utilization	99.6		%	81.2		%	95.0		%	76.6		%	Inland Barge Utilization	100.0		%	99.6		%	100.0		%	95.0		%
Offshore Barge Utilization	Offshore Barge Utilization	97.9		%	96.8		%	97.3		%	96.3		%	Offshore Barge Utilization	94.7		%	97.9		%	97.1		%	97.3		%

(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 June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

Marine transportation Segment Margin for the ~~2022~~2023 Quarter increased ~~$9.1~~$8.2 million, or ~~108%~~47%, from the ~~2021~~2022 Quarter. This increase is primarily attributable to higher ~~utilization and~~ day rates in our inland ~~business~~ and ~~higher day rates in our~~ offshore ~~business,~~businesses, including the M/T American Phoenix, during the ~~2022~~2023 Quarter. WeDemand for our offshore barge services to move intermediate and refined products from the Gulf Coast to the East Coast remained high during the 2023 Quarter due to the continued strength of refinery utilization rates as well as the lack of new supply of similar type vessels (primarily due to higher construction costs) as well as the retirement of older vessels in the market. These factors have ~~continued~~also contributed to ~~see~~ an overall increase in ~~demand~~spot and ~~utilization of~~term rates for our vessels as refinery utilization has increased and the supply of like maritime equipment is tight due to net equipment retirements. While we have continued to see increases in our day rates from both the 2021 Quarter and sequentially from the first quarter of 2022, we have continued to enter into short term contracts (less than a year) in the inland and offshore markets, includingservices. Additionally, the M/T American Phoenix ~~because we believe~~is under contract for the day rates currently being offered by the market have yet to fully recover from their cyclical lows. Additionally, during July 2022, the M/T American Phoenix went into her planned mandatory 30-45 day regulatory dry-dock and we have contracted her for four months beginning in September 2022remainder of 2023 with an investment grade customer at a more favorable rate than 2022, and we recently entered into a new three-and-a-half-year contract starting in January of ~~meaningfully higher than~~2024 with a credit-worthy counterparty at the ~~2022 Quarter rate.~~highest day rate we have received since we first purchased the vessel in 2014.

Six Months Ended June 30, ~~2022~~2023 Compared with Six Months Ended June 30, ~~2021~~2022

Marine transportation Segment Margin for the first six months of ~~2022~~2023 increased ~~$14.1~~$21.7 million, or ~~91%~~73%, from the first six months of ~~2021.~~2022. This increase is primarily attributable to ~~higher utilization and~~an increase in overall day rates in our inland ~~business~~ and ~~higher day rates in our~~ offshore business, including the M/T American ~~Phoenix, during the 2022 Quarter. While~~Phoenix. In addition, we have continued to see ~~increases~~strong demand for our barge services to move intermediate and refined products keeping utilization rates high across both periods. The strong demand from our customers as well as the lack of new supply of similar type vessels and the retirement of older vessels in our day rates from 2021 and throughout 2022, we have continued to enter into short term contracts (less than a year) in the inland and offshore markets, including the M/T American Phoenix, because we believe the day rates currently being offered by the market have ~~yet to fully recover from their cyclical lows.~~contributed the increase in day rates discussed above.

~~Other Costs, Interest and Income Taxes~~

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Other Costs, Interest and Income Taxes

General and administrative expenses


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(in thousands)				(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	$	13,004	$	10,368	$	24,956	$	19,789	Corporate	$	13,384	$	13,004	$	24,496	$	24,956
Segment	Segment	895		1,036		1,854		2,087		Segment	967		895		1,920		1,854
Long-term incentive compensation expense	Long-term incentive compensation expense	1,436		882		3,035		1,962		Long-term incentive compensation expense	2,509		1,436		4,962		3,035
Third party costs related to business development activities and growth projects	Third party costs related to business development activities and growth projects	5,330		621		5,942		735		Third party costs related to business development activities and growth projects	71		5,330		105		5,942
Total general and administrative expenses	Total general and administrative expenses	$	20,665	$	12,907	$	35,787	$	24,573	Total general and administrative expenses	$	16,931	$	20,665	$	31,483	$	35,787

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

Total general and administrative expenses for the 2023 Quarter decreased by $3.7 million from the 2022 Quarter ~~increased by $7.8 million~~ primarily due to ~~higher~~lower third party costs related to business development activities and growth projects as ~~a result of~~the 2022 Quarter included costs associated with the issuance of our Alkali senior secured notes and related sale of the ORRI Interests. We also incurred third party costs in the 2022 Quarter associated with the divestiture of our previously owned Independence Hub platform. ~~Additionally, we had increased corporate general and administrative expenses~~These decreases were partially offset by an increase in our long-term incentive compensation expense during the ~~2022~~2023 Quarter.

Six Months Ended June 30, ~~2022~~2023 Compared with Six Months Ended June 30, ~~2021~~2022

Total general and administrative expenses for the first six months of ~~2022 increased~~2023 decreased by ~~$11.2~~$4.3 million primarily due to ~~higher~~lower third party costs related to business development activities and growth projects as ~~a result of~~the 2022 Quarter included costs associated with the issuance of our Alkali senior secured notes and related sale of the ORRI ~~Interests. We also incurred third party~~Interests, as well as costs ~~in the 2022 Quarter~~ associated with the divestiture of our previously owned Independence Hub platform. ~~Additionally, we had increased corporate general and administrative expenses~~These decreases were partially offset by an increase in our long-term compensation expense during ~~the first six months of 2022.~~

2023.

Depreciation, depletion and amortization expense


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(in thousands)				(in thousands)					(in thousands)				(in thousands)
Depreciation and depletion expense	Depreciation and depletion expense	$	70,947	$	64,852	$	137,717	$	128,466	Depreciation and depletion expense	$	65,181	$	70,947	$	135,635	$	137,717
Amortization expense	Amortization expense	2,726		2,689		5,462		5,361		Amortization expense	3,246		2,726		5,952		5,462
Total depreciation, depletion and amortization expense	Total depreciation, depletion and amortization expense	$	73,673	$	67,541	$	143,179	$	133,827	Total depreciation, depletion and amortization expense	$	68,427	$	73,673	$	141,587	$	143,179

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

Total depreciation, depletion and amortization expense for the 2023 Quarter decreased by $5.2 million from the 2022 ~~Quarter increased by $6.1 million.~~Quarter. This ~~increase~~decrease is primarily attributable to the 2022 Quarter including an acceleration of depreciation on our asset retirement obligation assets as a result of updates to the estimated timing and costs associated with certain of our non-core offshore gas assets.

Six Months Ended June 30, 2023 Compared with Six Months Ended June 30, 2022

Total depreciation, depletion and amortization expense for the first six months of 2023 decreased by $1.6 million from the first six months of 2022. This decrease is primarily attributable to 2022 including an acceleration of depreciation on our asset retirement obligation assets as a result of updates to the estimated timing and costs associated with certain of our non-core offshore gas assets. This decrease was partially offset by an overall increase in our depreciable asset base due to our continued growth and maintenance capital expenditures and placing new assets into service subsequent to the ~~2021 Quarter.~~

~~Six Months Ended~~period ended June 30, ~~2022 Compared with Six Months Ended June 30, 2021~~

Total depreciation, depletion and amortization expense for the first six months of 2022 increased by $9.4 million. This increase is primarily attributable to an overall increase in our depreciable asset base due to our continued growth and maintenance capital expenditures and placing new assets into service subsequent to the first six months of 2021.2022.

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Interest expense, net

Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
(in thousands) (in thousands)
Interest expense, senior secured credit facility (including commitment fees) $ 1,680 $ 5,812 $ 3,627 $ 13,243
Interest expense, Alkali senior secured notes 3,105 — 3,105 —
Interest expense, senior unsecured notes 52,980 51,859 106,059 100,194
Amortization of debt issuance costs, premium and discount 2,116 2,255 4,151 4,970
Capitalized interest (3,922) (757) (5,879) (1,409)
Interest expense, net $ 55,959 $ 59,169 $ 111,063 $ 116,998


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	5,095	$	1,680	$	9,491	$	3,627
Interest expense, Alkali senior secured notes	6,242		3,105		12,484		3,105
Interest expense, senior unsecured notes	57,873		52,980		114,185		106,059
Amortization of debt issuance costs, premium and discount	2,279		2,116		4,640		4,151
Capitalized interest	(9,866)		(3,922)		(18,323)		(5,879)
Interest expense, net	$	61,623	$	55,959	$	122,477	$	111,063

Three Months Ended June 30, ~~2022~~2023 Compared with Three Months Ended June 30, ~~2021~~2022

~~Net interest~~Interest expense, net for the ~~2022~~2023 Quarter ~~decreased~~increased by ~~$3.2~~$5.7 million ~~primarily~~ due to ~~lower~~an increase in interest on our Alkali senior secured notes issued in May 2022, an increase in interest on our senior secured credit facility, and an increase in interest on our senior unsecured notes, which was partially offset by higher capitalized interest. The ~~decrease~~increase in interest expense associated with our senior secured credit facility is primarily due to ~~a lower outstanding balance throughout~~an increase in the SOFR rate, which is one of the main components of our interest rate, compared to the 2022 Quarter, ~~as a result of: (i)~~and higher outstanding indebtedness during the ~~proceeds we received from the additional issuance of $250 million~~2023 Quarter. The increase in ~~aggregate principal of~~interest expense associated with our ~~2027 Notes in April 2021; (ii) the proceeds from the sale of a noncontrolling interest in our CHOPS pipeline in November 2021; and (iii) the excess proceeds we received from~~senior unsecured notes was primarily related to the issuance of our ~~Alkali senior secured notes~~2030 Notes in ~~May 2022, all of~~January 2023, which have a higher principal and interest rate than the 2024 Notes that were ~~used to pay down the outstanding balance under~~redeemed in January 2023 (see further discussion in Note 10 in our ~~senior secured credit facility. Additionally, we had~~Unaudited Condensed Consolidated Financial Statements). This increase was partially offset by higher capitalized interest during the ~~2022~~2023 Quarter as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction ~~projects, both of which are being funded internally.~~

~~This decrease was offset by increased interest expense associated with our Alkali senior secured notes due 2042 that were issued during May 2022, which bear interest at 5.875%.~~projects.

Six Months Ended June 30, ~~2022~~2023 Compared with Six Months Ended June 30, ~~2021~~2022

Net interest expense for the first six months of ~~2022 decreased~~2023 increased by ~~$5.9~~$11.4 million ~~primarily~~ due to ~~lower~~an increase in interest on our Alkali senior secured notes issued in May 2022, an increase in interest on our senior secured credit ~~facility.~~facility, and an increase in interest on our senior unsecured notes, which was partially offset by higher capitalized interest. The ~~decrease~~increase in interest expense associated with our senior secured credit facility is primarily due to ~~a lower outstanding balance throughout~~an increase in the ~~2022 Quarter as a result of: (i)~~SOFR rate, which is one of the ~~proceeds we received from the additional issuance of $250 million in aggregate principal~~main components of our ~~2027 Notes~~interest rate, compared to the first six months of 2022, and higher outstanding indebtedness during the first six months of 2023. The increase in ~~April 2021; (ii) the proceeds from the sale of a noncontrolling~~ interest inexpense associated with our ~~CHOPS pipeline in November 2021; and (iii) the excess proceeds we received from~~senior unsecured notes was primarily related to the issuance of our ~~Alkali senior secured notes~~2030 Notes in ~~May 2022, all of~~January 2023, which have a higher principal and interest rate than the 2024 Notes that were ~~used to pay down the outstanding balance under our senior secured credit facility. Additionally, we had~~redeemed in January 2023. This increase was partially offset by higher capitalized interest during the ~~2022 Quarter~~first six months of 2023 as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction ~~projects, both of which are being funded internally.~~

This decrease was offset by increased interest expense associated with our senior unsecured notes as a result of our additional issuance of $250 million in aggregate principal of our 2027 Notes in April 2021, which bears interest at 8% and issuance of our Alkali senior secured notes due 2042 on May 17, 2022, which bear interest at 5.875%.

projects.

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

On January 25, 2023, we issued $500.0 million in aggregate principal amount of 8.875% senior unsecured notes due April ~~8, 2021, we entered into~~15, 2030 (the “2030 Notes”). Interest payments are due April 15 and October 15 of each year with the initial interest payment due on October 15, 2023. The net proceeds were used to purchase $316.3 million of our ~~credit agreement, which initially provided for~~existing 2024 Notes, including the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that ended January 24, 2023. The remaining proceeds at that time were used to repay a ~~$950 million~~portion of the borrowings outstanding under our senior secured credit facility ~~comprised~~and for general partnership purposes. On January 26, 2023, we issued notice of redemption for the remaining principal of $24.8 million of our ~~Revolving Loan~~2024 Notes and discharged the indebtedness with ~~a borrowing capacity of $650~~respect to the 2024 Notes on February 14, 2023.

On February 17, 2023, we entered into the Sixth Amended and Restated Credit Agreement (our “new credit agreement”) to replace our Fifth Amended and Restated Credit Agreement. Our new credit agreement provides for an $850 million and our Term Loan with a borrowing capacity of $300 million, with the ability to increase the aggregate size of the Revolving Loan by an additional $200 million subject to lender consent and certain other customary conditions. Our Term Loan was paid off in full on November 17, 2021 with a portion of the gross proceeds of $418 million received from the sale of a 36% minority interest in CHOPS. Oursenior secured revolving credit facility. The new credit agreement matures on ~~March 15, 2024,~~February 13, 2026, subject to extension at our request for one additional year on up to two occasions and subject to certain ~~conditions.~~

~~On April 22, 2021 we completed our offering of an additional $250~~conditions, unless more than $150 million ~~in aggregate principal amount~~ of our ~~2027 Notes. The additional $250 million~~2025 Notes remain outstanding as of ~~notes have identical terms as (other than with respect to issue price) and constitute part of~~June 30, 2025, in which case the same series as our 2027 Notes and the net proceeds from this additional offering were used for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our Revolving Loan.new credit agreement matures on such date.

On May 17, 2022, Genesis Energy, L.P., through its newly created indirect unrestricted subsidiary, GA ORRI, issued $425 million principal amount of our 5.875% Alkali senior secured notes due 2042 to certain institutional investors, secured by GA ORRI’s fifty-year limited term overriding royalty interest in substantially all of the Company’s Alkali Business trona mineral leases. The issuance generated net proceeds of $408 million, net of the issuance discount of $17 million. We make quarterly interest payments on our Alkali senior secured notes until March 2024, at which time we begin making quarterly principal and interest payments through the maturity date. We used a portion of net proceeds from the issuance to fully redeem the outstanding Alkali Holdings preferred units and utilized the remainder to repay a portion of the outstanding borrowings under our ~~Revolving Loan.~~senior secured credit facility. The redemption of our Alkali Holdings preferred units, which carried an implied interest rate of 12-13%, and the issuance of our Alkali senior secured notes with a coupon rate of 5.875%, has allowed us to simplify ~~and~~ our capital structure and lower our cost of capital, provide us additional flexibility under our ~~Revolving Loan,~~senior secured credit facility, and remove any risk of refinancing our Alkali Holdings preferred units that were initially due in 2026.

On April 3, 2023, we entered into a purchase agreement with the Class A Convertible Preferred unitholders whereby we redeemed 741,620 Class A Convertible Preferred Units at a purchase price of $33.71 per unit. On July 3, 2023, we entered into another purchase agreement with the Class A Convertible Preferred unitholders whereby we redeemed an additional 741,620 Class A Convertible Preferred Units at a purchase price of $33.71 per unit. The redemption of these Class A Convertible Preferred Units, which carried an annual coupon rate of 11.24%, allowed us to lower our overall cost of capital.

The successful completion of our new credit agreement (including its extended maturity and ~~leverage flexibility)~~increased borrowing capacity), the refinancing of our previously held ~~2023~~2024 Notes, and the ~~sale~~continued efforts to simplify our capital structure and lower our overall cost of ~~a minority interest in CHOPS~~capital has ~~resulted in no scheduled maturities of long-term~~extended our debt ~~until 2024~~maturity runway and has provided us a significant amount of ~~available borrowing capacity under our Revolving Loan, subject~~liquidity to ~~compliance with the covenants in our credit agreement, to, amongst other things,~~ utilize for funding the remaining growth capital expenditures associated with the Granger expansion and our offshore growth projects (as discussed in further detail below. We also received $40 million, or $32 million net to our ownership interests, for the sale of our 80% owned Independence Hub platform which allowed us to further increase our borrowing capacity as we move forward into the second half of 2022 and beyond.below), amongst other things. The available borrowing capacity under our ~~Revolving Loan~~senior secured credit facility at June 30, ~~2022~~2023 is ~~$610.9 million.~~$707.9 million, subject to compliance with covenants. Our new credit agreement does not include a “borrowing base” limitation except with respect to our inventory loans.

We anticipate that our future internally-generated funds and the funds available under our senior secured credit ~~agreement~~facility 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 senior secured credit facility, proceeds from the sale of non-core assets, the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances and the proceeds from issuances of equity (common and preferred) and senior unsecured or secured notes.

Table of Contents

Our primary cash requirements consist of:

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

•routine operating expenses;

•capital growth (as discussed in more detail below) and maintenance projects;

•~~acquisitions of assets or businesses;~~

•interest payments related to outstanding debt;

•asset retirement obligations; ~~and~~

•quarterly cash distributions to our preferred and common ~~unitholders.~~unitholders; and

•acquisitions of assets or businesses.

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 senior secured 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.

~~Table of Contents~~

At June 30, ~~2022,~~2023, our ~~long-term~~ debt totaled approximately ~~$3.3~~$3.6 billion, consisting of ~~$34.6~~$133.6 million outstanding under our senior secured credit facility (including ~~$14.3~~$16.3 million borrowed under the inventory sublimit tranche), ~~$2.9~~$3.0 billion of senior unsecured notes ~~net~~ and ~~$402.2~~$425.0 million of Alkali senior secured notes ~~net,~~(of which $5.8 million is current), which are secured by the ORRI Interests. Our senior unsecured notes ~~net~~ balance is comprised of ~~$339.5 million carrying amount due June 2024, $531.0~~$534.8 million carrying amount due October 2025, ~~$341.4~~$339.3 million carrying amount due May 2026, ~~$994.2~~$981.2 million carrying value due January 2027, ~~and $682.4~~$679.4 million carrying amount due February ~~2028. We remain focused on continuing to reduce our leverage.~~

~~On September 23, 2019, we announced the GOP. We entered into agreements with BXC for the purchase of up to approximately $350~~2028 and $500.0 million of Alkali Holdings preferred units. The proceeds received from BXC to date have been utilized to fund a portion of the anticipated cost of the GOP. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year. On May 17, 2022, utilizing a portion of the proceeds we received from the issuance of our Alkali senior secured notes, we fully redeemed the 251,750 outstanding Alkali Holdings preferred units at a Base Preferred Return Amount of $288.6 million. As of June 30, 2022, there were no Alkali Holdings preferred units outstanding and we plan to fund the remaining capital expenditures associated with the GOP internally.carrying amount due April 2030.

Shelf Registration 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.

We have a universal shelf registration statement (our “2021 Shelf”) on file with the SEC which we filed on April 19, 2021 to replace our existing universal shelf registration statement that expired on April 20, 2021. Our 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 2021 Shelf is set to expire in April 2024. We expect to file a replacement universal shelf registration statement before our 2021 Shelf expires.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our common and preferred distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our senior secured credit facility and/or to fund a portion of our capital ~~expenditures and asset retirement obligations (if any).~~expenditures. 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 and interest charges, and the timing of accounts receivable collections from our customers.

We typically sell our ~~purchased~~ crude oil in the same month in which we ~~acquire~~purchase it, so we do not need to rely on borrowings under our senior secured 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 senior secured 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 products to our customers ~~all within a relatively short time frame. If~~domestically and internationally. When we do experience any differences in timing ofbetween the extraction, processing and sales of ~~our~~this trona or ~~alkali, or delays in collections from~~Alkali products, including the logistics and transportation to our ~~sales to~~ customers, itthis could impact the cash requirements for these ~~activities in the short term.~~activities.

The storage of our inventory of crude oil, petroleum products and alkali 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 (or pay for extraction and processing activities in the case of alkali products), we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil or petroleum products (or extraction/processing of alkali 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

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sale of the stored crude oil, petroleum products or alkali products. Additionally, for our exchange-traded derivatives, we may be required to deposit margin funds with the ~~NYMEX~~respective exchange 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 senior secured credit facility or use cash on hand to fund the deposits.

See Note 1415 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities ~~for~~during the ~~2022~~2023 Quarter and ~~2021~~2022 Quarter.

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Net cash flows provided by our operating activities for the six months ended June 30, ~~2022~~2023 were ~~$158.3~~$255.3 million compared to ~~$188.2~~$158.3 million for the six months ended June 30, ~~2021.~~2022. The ~~decrease~~increase in cash ~~flow~~flows from operating activities is primarily attributable to changes in working capital between the two periods ~~with the primary difference related to higher interest payments~~ and ~~changes in~~ our ~~inventory positions during 2022 compared to 2021. See~~ ~~Note 14~~ ~~in our Unaudited Condensed Consolidated Financial Statements for information regarding the timing of our interest payments. These changes were partially offset by an~~reported increase in ~~our operations and reported~~ Segment Margin during 2023 relative to Segment Margin in 2022 (which included the ~~2022 Quarter.~~$32 million distribution received from one of our unrestricted subsidiaries, Independence Hub LLC, from the sale of its platform asset that was classified as a cash inflow from investing activities).

Capital Expenditures and Distributions Paid to Our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal growth projects ~~maintenance capital expenditures~~ and distributions we pay to our ~~preferred~~common and ~~common~~preferred unitholders. We finance maintenance capital expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and internal growth projects) with borrowings under our senior secured credit facility, equity issuances (common and preferred units), the issuance of senior unsecured or secured notes, and/or the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.

Capital Expenditures for Fixed and Intangible Assets and Equity Investees

The following table summarizes our expenditures for fixed and intangible assets and equity investees in the periods indicated:


		Six Months Ended June 30,					Six Months Ended June 30,
		2022		2021			2023		2022
		(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	$	3,776	$	7,371	Offshore pipeline transportation assets	$	2,044	$	3,776
Sodium minerals and sulfur services assets		25,176		16,032
Soda and sulfur services assets						Soda and sulfur services assets	29,682		25,176
Marine transportation assets	Marine transportation assets	14,129		22,871		Marine transportation assets	17,892		14,129
Onshore facilities and transportation assets	Onshore facilities and transportation assets	867		3,453		Onshore facilities and transportation assets	3,140		867
Information technology systems and corporate assets	Information technology systems and corporate assets	2,244		190		Information technology systems and corporate assets	541		2,244
Total maintenance capital expenditures	Total maintenance capital expenditures	46,192		49,917		Total maintenance capital expenditures	53,299		46,192
Growth capital expenditures:	Growth capital expenditures:					Growth capital expenditures:
Offshore pipeline transportation assets(1)	Offshore pipeline transportation assets(1)	74,708		23,578		Offshore pipeline transportation assets(1)	139,782		74,708
Sodium minerals and sulfur services assets		40,070		74,566
Soda and sulfur services assets						Soda and sulfur services assets	16,925		40,070
Marine transportation assets	Marine transportation assets	—		—		Marine transportation assets	2,155		—
Onshore facilities and transportation assets	Onshore facilities and transportation assets	—		133		Onshore facilities and transportation assets	553		—
Information technology systems and corporate assets	Information technology systems and corporate assets	4,433		4,211		Information technology systems and corporate assets	5,191		4,433
Total growth capital expenditures	Total growth capital expenditures	119,211		102,488		Total growth capital expenditures	164,606		119,211
Total capital expenditures for fixed and intangible assets	Total capital expenditures for fixed and intangible assets	165,403		152,405		Total capital expenditures for fixed and intangible assets	217,905		165,403

Capital expenditures related to equity investees	Capital expenditures related to equity investees	2,976		—		Capital expenditures related to equity investees	2,197		2,976
Total capital expenditures	Total capital expenditures	$	168,379	$	152,405	Total capital expenditures	$	220,102	$	168,379

~~Expenditures~~(1)Growth capital expenditures in our offshore pipeline transportation segment for ~~capital assets to grow~~2023 and 2022 represent 100% of 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.costs incurred.

Growth Capital Expenditures

On September 23, 2019, we announced the GOP along with the issuance of the Alkali Holdings preferred units, which were anticipated to fund up to the total estimated cost of the GOP. The anticipated completion date of the project is the ~~third quarter~~second half of 2023. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per

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year. During the fourth quarter of 2021, we made the decision to fund the remaining capital expenditures associated with the GOP ~~internally.~~internally in lieu of issuing additional Alkali Holdings preferred units, and during the second quarter of 2022, we fully redeemed the outstanding Alkali Holdings preferred units.

During 2022, we entered into definitive agreements to provide transportation services for 100% of the crude oil production associated with two separate standalone deepwater developments that have a combined production capacity of

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approximately 160,000 barrels per day. In conjunction with these agreements, we expect ~~to spend gross~~total capital expenditures of approximately ~~$600 million (or approximately $500~~$550 million net to our ownership ~~interests) over the next three years~~interests (which began in 2022) to: (i) expand the current capacity of the CHOPS pipeline; and (ii) construct a new 100% owned, approximately 105 mile, 20” diameter crude oil pipeline (the “SYNC pipeline”) to connect one of the developments to our existing asset footprint in the Gulf of Mexico. We plan to complete the construction in line with the producers’ plan for first oil achievement, which is currently expected in late 2024 or 2025. The producer agreements include long term take-or-pay arrangements and, accordingly, we are able to receive a project completion credit for purposes of calculating the leverage ratio under our senior secured credit facility throughout the construction period.

We plan to fund our estimated growth capital expenditures utilizing the available borrowing capacity under our ~~Revolving Loan~~senior secured credit facility and our recurring cash flows generated from operations, which we anticipate to increase throughout 2022 and into 2023 as a result of increased offshore volumes from King’s Quay and Argos, favorable export pricing in our Alkali Business, and the restart of our original and expanded Granger facility in 2023.operations.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred during ~~2022~~2023 primarily related to expenditures in our marine transportation segment to replace and upgrade certain equipment associated with our barge and fleet vessels during our planned and unplanned dry-docks and in our Alkali Business ~~which is included in our sodium minerals and sulfur services segment,~~ due to the costs to maintain our related equipment and facilities. Additionally, our offshore transportation assets incur maintenance capital expenditures to replace, maintain and upgrade equipment at certain of our offshore platforms and pipelines that we operate. 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 May ~~13, 2022,~~15, 2023, we paid a distribution of $0.15 per unit related to the first quarter of ~~2022.~~2023. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of ~~$0.7374~~$0.9473 per preferred unit (or ~~$2.9496~~$3.7892 on an annualized basis) for each preferred unit held of record. These distributions were paid on May ~~13, 2022~~15, 2023 to unitholders holders of record at the close of business April ~~29, 2022.~~28, 2023.

OnIn July ~~12, 2022,~~2023, we ~~announced the~~declared our quarterly distribution to our common unitholders of $0.15 per ~~common~~ unit totaling $18.4 million with respect to the ~~2022~~2023 Quarter and a distribution of ~~$0.7374~~$0.9473 per Class A Convertible Preferred Unit (or ~~$2.9496~~$3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on August ~~12, 2022~~14, 2023 to unitholders of record at the close of business on July ~~29, 2022. Information on our recent distribution history is included in~~ ~~Note 10~~ ~~to our Unaudited Condensed Consolidated Financial Statements.~~31, 2023.

Guarantor Summarized Financial Information

Our ~~$2.9~~$3.0 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except GA ORRI and GA ORRI Holdings and certain other subsidiaries. The remaining non-guarantor subsidiaries are indirectly owned by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries. See Note 910 in our Unaudited Condensed Consolidated Financial Statements 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~~non-Guarantor 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

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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.

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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.

On May 17, 2022, we entered into our credit agreement amendment, which designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries under our credit agreement. In addition, the credit agreement amendment re-designatedGenesis Alkali Holdings Company LLC, Genesis Alkali Holdings, LLC, Genesis Alkali, LLC and Genesis Alkali Wyoming, LP (the subsidiary entities that own our Alkali Business, other than the ORRI Interests) as restricted entities and guarantors of our credit agreement. On May 17, we designated GA ORRI and GA ORRI Holdings as unrestricted subsidiaries and reclassified the entities that originally held our Alkali Business as restricted subsidiaries under the indentures governing our senior unsecured notes. The Alkali Business was historically presented as non-guarantor subsidiaries and because of such designation will now be presented as guarantor subsidiaries. The changes made did not impact the Company’s previously reported consolidated net operating results, financial position, or cash flows.

The summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a combined basis have been retrospectively adjusted to reflect these updates to our guarantor subsidiaries as though the Alkali Business had been presented as guarantor subsidiaries in the periods presented.

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~~among the Guarantor Subsidiaries (which includes related receivable and payable ~~balances,~~balances) and the investment in and equity earnings from the ~~Non-Guarantor~~non-Guarantor Subsidiaries.


Balance Sheets	Genesis Energy, L.P. and Guarantor Subsidiaries
	June 30, ~~2022~~2023
	(in thousands)
ASSETS:
Current assets	$	~~561,927~~926,303
Fixed assets and mineral leaseholds, net	~~3,581,435~~3,750,543
Non-current assets(1)	~~879,855~~976,110

LIABILITIES AND CAPITAL:~~(1)~~(2)
Current liabilities	~~489,014~~823,420
Non-current liabilities	~~3,369,313~~3,647,003
Class A Convertible Preferred Units	~~790,115~~865,802

Statement of Operations

Genesis Energy, L.P. and Guarantor Subsidiaries

Six Months Ended
June 30, ~~2022~~2023

(in thousands)

Revenues(3)

~~1,296,155~~1,533,999

Operating costs

~~1,205,840~~1,413,430

Operating income

~~90,315~~120,569

Income before income taxes

~~20,038~~41,509

Net income~~(1)~~(2)

~~19,180~~40,336

Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units

~~(37,368)~~(46,912)

Net loss attributable to common unitholders

~~(18,188)~~(6,576)

(1)Excluded from non-current assets in the table above are $10.0 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of June 30, 2023.

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

(3)Excluded from ~~non-current assets~~revenues in the table above ~~is $8.2~~are $1.3 million of ~~net intercompany receivables due to Genesis Energy, L.P. and the~~sales from Guarantor Subsidiaries ~~from~~to non-Guarantor Subsidiaries for the ~~Non-Guarantor Subsidiaries as of~~six months ended June 30, ~~2022.~~2023.

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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 June 30,					Three Months Ended June 30,
		2022		2021			2023		2022
		(in thousands)					(in thousands)
Net income (loss) attributable to Genesis Energy, L.P.		$	35,347	$	(41,682)
Net income attributable to Genesis Energy, L.P.						Net income attributable to Genesis Energy, L.P.	$	49,344	$	35,347
Income tax expense	Income tax expense	571		525		Income tax expense	290		571
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	76,277		69,684		Depreciation, depletion, amortization and accretion	71,754		76,277

Plus (minus) Select Items, net	Plus (minus) Select Items, net	51,351		47,440		Plus (minus) Select Items, net	14,959		51,351
Maintenance capital utilized(1)	Maintenance capital utilized(1)	(14,150)		(13,300)		Maintenance capital utilized(1)	(16,600)		(14,150)
Cash tax expense	Cash tax expense	(150)		(195)		Cash tax expense	(159)		(150)
Distributions to preferred unitholders	Distributions to preferred unitholders	(18,684)		(18,684)		Distributions to preferred unitholders	(23,314)		(18,684)
Redeemable noncontrolling interest redemption value adjustments(2)	Redeemable noncontrolling interest redemption value adjustments(2)	22,620		5,766		Redeemable noncontrolling interest redemption value adjustments(2)	—		22,620
Gain on sale of asset, net to our ownership interest(3)	Gain on sale of asset, net to our ownership interest(3)	(32,000)		—		Gain on sale of asset, net to our ownership interest(3)	—		(32,000)

Available Cash before Reserves	Available Cash before Reserves	$	121,182	$	49,554	Available Cash before Reserves	$	96,274	$	121,182

(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 ~~2022~~2023 Quarter and ~~2021~~2022 Quarter were ~~$24.3~~$29.3 million and ~~$23.8~~$24.3 million, respectively.

(2)~~Includes~~The 2022 Quarter includes PIK distributions and accretion on the redemption ~~feature attributable to each period, and valuation adjustments to the redemption feature~~feature. The associated Alkali Holdings preferred units were fully redeemed during the ~~2022 Quarter.~~second quarter of 2022.

(3)On April 29, 2022, we sold our Independence ~~HUB~~Hub platform and recognized a gain on the sale of $40.0 million, of which $32.0 million was attributable to our 80% ownership interest.

We define Available Cash before Reserves (“Available Cash before Reserves”) as Net income (loss) attributable to Genesis Energy, L.P. 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 ~~tax expense.~~distributions paid to our Class A convertible 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 June 30,						Three Months Ended June 30,
			2022		2021				2023		2022
			(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)	$	16,477	$	6,446		Differences in timing of cash receipts for certain contractual arrangements(1)	$	11,559	$	16,477
		Distribution from unrestricted subsidiaries not included in income(2)	32,000		17,500			Distribution from unrestricted subsidiaries not included in income(2)	—		32,000

		Certain non-cash items:						Certain non-cash items:
		Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(3)	(8,319)		14,750			Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(3)	2,888		(8,319)
		Loss on debt extinguishment	501		—			Loss on debt extinguishment	3		501
		Adjustment regarding equity investees(4)	4,160		7,692			Adjustment regarding equity investees(4)	5,867		4,160
		Other	(589)		(67)			Other	(7,197)		(589)
		Sub-total Select Items, net	44,230		46,321			Sub-total Select Items, net	13,120		44,230
II.	II.	Applicable only to Available Cash before Reserves					II.	Applicable only to Available Cash before Reserves
		Certain transaction costs(5)	5,330		621			Certain transaction costs(5)	71		5,330

		Other	1,791		498			Other	1,768		1,791
		Total Select Items, net(6)	$	51,351	$	47,440		Total Select Items, net(6)	$	14,959	$	51,351

(1)Includes the difference in timing of cash receipts from or billings to 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)The 2022 Quarter includes $32.0 million in cash receipts associated with the sale of the Independence Hub platform by our 80% owned unrestricted subsidiary (as defined under our credit agreement), Independence Hub, LLC. The 2021 Quarter includes $17.5 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. We received the last principal payment associated with our previously owned NEJD pipeline in the fourth quarter of 2021. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our senior secured credit facility.

(3)The 2023 Quarter includes unrealized losses of $2.9 million from the valuation of our commodity derivative transactions (excluding fair value hedges). The 2022 Quarter includes unrealized losses of $2.3 million from the valuation of our commodity derivative transactions (excluding fair value hedges), and an unrealized gain of $10.7 ~~million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. The 2021 Quarter includes an unrealized loss of $14.3~~ million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.

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

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

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

Non-GAAP Financial Measures

General

To help evaluate our business, ~~we use~~this Quarterly Report on Form 10-Q includes 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 Net Income ~~(Loss)~~ attributable Genesis Energy, L.P. to total Segment Margin is also included in our segment disclosure in Note 1213 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~~have 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 expectations for us; and certain information regarding some of our peers. Additionally, our board of

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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,

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analysts and other 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.

Segment Margin

We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable Select ~~Items.~~Items (defined below). 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. 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.

A reconciliation of Net income ~~(loss)~~ attributable to Genesis Energy, L.P. to total Segment Margin is included in our segment disclosure in Note 1213 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 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.

Prior to 2014, 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.

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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.

Beginning with 2014, we believe a substantial amount of our maintenance capital expenditures from time to time have been and will continue to be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets,

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(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 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 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.

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.

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. Because we did not initially use our maintenance capital utilized measure before 2014, our maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

Critical Accounting Estimates

There have been no new or material changes to the critical accounting estimates discussed in our Annual Report that are of significance, or potential significance, to the Company.

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, 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:

•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, all of which may be affected by

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economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events (including the war in Ukraine), global pandemics, inflation, the actions of OPEC and other oil exporting nations, conservation and technological advances;

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

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

•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;~~facilities, including due to adverse weather events;

•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;~~rates, including the result of any economic recession or depression that has occurred or may occur in the future;

•the impact of natural disasters, international military conflicts (such as the conflict in Ukraine), global 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;

•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.

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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 be specifically described in our Quarterly Reports on Form 10-Q, 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 1516 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. Based upon~~10-Q and have determined that evaluation, management identified a material weakness in our internal control over financial reporting as we did not effectively operate control activities to reach the appropriate conclusion on the accounting treatment for certain revenue contract amendments executed during the second quarter of 2022. Solely as a result of this material weakness, our chief executive officer and chief financial officer concluded that oursuch disclosure controls and procedures ~~were not~~are effective ~~as of the last day of the period covered by this report. This~~in ensuring that material ~~weakness did not, however, result in a misstatement~~information required to the reported consolidated financial statements, and notwithstanding the material weakness, management, including our chief executive officer and chief financial officer, believes the consolidated financial statements includedbe disclosed in this Quarterly Report on Form 10-Q ~~fairly represent in all material respects our financial condition, results of operations~~is accumulated and ~~cash flows at~~communicated to them and ~~for the periods presented in accordance with GAAP.~~

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

~~In order to address the material weakness described above,~~ our management ~~intends~~ to implement a remediation plan to address the control deficiency that led to this material weakness, including plans for additional review procedures, enhancements in the relevant accounting processes and continuing education associated with the review of revenue contracts to evaluate, resolve and document the proper accounting in accordance with GAAP.allow timely decisions regarding required disclosures.

~~Changes in Internal Control Over Financial Reporting~~

~~Except as noted above, there have been~~There were no changes ~~in internal control over financial reporting~~ during the ~~quarter ended June 30, 2022~~2023 Quarter that ~~have~~ 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, ~~2021~~2022 (the “Annual Report”). There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will exceed a specified threshold. Pursuant to recent SEC amendments to this item, we will be using a threshold of $1 million for such proceedings. We believe that such threshold is reasonably designed to result in disclosure of environmental proceedings that are material to our business or financial condition. Applying this threshold, there are no environmental matters to disclose for this period.

Item 1A. Risk Factors

There has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2021.~~2022.

For additional information about our risk factors, see Item 1A of our Annual Report, 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 ~~2022~~2023 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 filed on November 15, 1996, 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~~’sCompany’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).

3.3

~~Fifth~~Sixth Amended and Restated Credit Agreement, dated as of ~~Limited Partnership of~~February 17, 2023, 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 (incorporated by reference to Exhibit ~~5.1~~10.1 to the ~~Company~~’sCompany’s Current Report on Form 8-K ~~dated January 3, 2011,~~filed on February 23, 2023, 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~~’sCompany’s Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).

~~3.7~~3.5

Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the ~~Company~~’sCompany’s Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).

~~3.8~~3.6

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~~’sCompany’s Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).

~~3.9~~3.7

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~~’sCompany’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).

4.2

~~Seventeenth~~Nineteenth Supplemental Indenture, ~~for 5.625% Senior Notes due 2024,~~ dated as of ~~June~~February 28, ~~2021,~~2023, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the ~~Guarantors~~subsidiary guarantors named therein and ~~Regions Bank, as trustee.~~the Trustee.

~~4.3~~

Seventeenth Supplemental Indenture for 6.50% Senior Notes due 2025, 6.250% Senior Notes due 2026, 7.750% Senior Notes due 2028, and 8.0% Senior Notes due 2027, dated as of June 28, 2021, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and Regions Bank, as trustee.

~~10.1~~

~~Second~~ ~~Amendment and Consent to Fifth Amended and Restated Credit Agreement, dated as of~~ ~~May~~ ~~17, 202~~2 ~~, 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, 2023, 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.

Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.

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:	August ~~2, 2022~~3, 2023	By:	/s/ RKRISTEN O. JESULAITIS~~OBERT~~ ~~V. DEERE~~
			~~Robert V. Deere~~Kristen O. Jesulaitis
			Chief Financial Officer
			(Duly Authorized Officer)

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	Six Months Ended June 30, 2021
	Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	137,605	$	—	$	87,957	$	42,570	$	268,132
Product Sales	—		417,212		—		292,568		709,780
Refinery Services	—		47,162		—		—		47,162
	$	137,605	$	464,374	$	87,957	$	335,138	$	1,025,074


	Contract Assets		Contract Liabilities
	Current Assets- Other			Accrued Liabilities		Other Long-Term Liabilities
Balance at December 31, 2021	$	13,563		$	2,619	$	19,028
Balance at June 30, 2022	751			11,898		26,369


Remainder of	2022	$	6,291
	2023	$	10,583
	2024	$	9,767
	2025	$	10,469
	2026	$	8,216


Remainder of	2022	$	6,110
	2023	$	11,983
	2024	$	11,618
	2025	$	11,393
	2026	$	11,093


	June 30,		December 31,
	2022		2021
Accounts receivable - trade, net:
ANSAC	$	89,923	$	64,799
Accounts payable - trade:
ANSAC	$	2,340	$	116