Enhanced Investments - Financial Portal

Published: 2023-11-02 00:00:00 ET

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 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.)

811 Louisiana, Suite 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 122,424,321 Class A Common Units and 39,997 Class B Common Units outstanding as of November 1, 2023.

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GENESIS ENERGY, L.P.

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		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets as of September 30, 2023 (unaudited) and December 31, 2022	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Comprehensive Income	5
	Unaudited Condensed Consolidated Statements of Partners’ Capital	6
	Unaudited Condensed Consolidated Statements of Cash Flows	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
	1. Organization and Basis of Presentation and Consolidation	8
	2. Recent Accounting Developments	8
	3. Revenue Recognition	9
	4. Business Consolidation	10
	5. Lease Accounting	12
	6. Inventories	13
	7. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations	14
	8. Equity Investees	15
	9. Intangible Assets	16
	10. Debt	17
	11. Partners’ Capital, Mezzanine Capital and Distributions	18
	12. Net Income Per Common Unit	21
	13. Business Segment Information	22
	14. Transactions with Related Parties	25
	15. Supplemental Cash Flow Information	25
	16. Derivatives	26
	17. Fair-Value Measurements	30
	18. Commitments and Contingencies	31

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	55
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
SIGNATURES		58

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)


	September 30, 2023		December 31, 2022
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,101	$	7,930
Restricted cash	18,804		18,637
Accounts receivable - trade, net	871,298		721,567
Inventories	126,946		78,143

Other	53,396		26,770
Total current assets	1,091,545		853,047
FIXED ASSETS, at cost	6,248,511		5,865,038
Less: Accumulated depreciation	(1,925,879)		(1,768,465)
Net fixed assets	4,322,632		4,096,573
MINERAL LEASEHOLDS, net of accumulated depletion	541,866		545,122

EQUITY INVESTEES	270,294		284,486
INTANGIBLE ASSETS, net of amortization	141,703		127,320
GOODWILL	301,959		301,959
RIGHT OF USE ASSETS, net	229,785		125,277
OTHER ASSETS, net of amortization	38,658		32,208
TOTAL ASSETS	$	6,938,442	$	6,365,992
LIABILITIES AND CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	660,577	$	427,961
Accrued liabilities	363,136		281,146

Total current liabilities	1,023,713		709,107
SENIOR SECURED CREDIT FACILITY	198,400		205,400
SENIOR UNSECURED NOTES, net of debt issuance costs and premium	3,011,386		2,856,312
ALKALI SENIOR SECURED NOTES, net of debt issuance costs and discount	394,320		402,442
DEFERRED TAX LIABILITIES	17,577		16,652
OTHER LONG-TERM LIABILITIES	541,373		400,617
Total liabilities	5,186,769		4,590,530

MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 23,853,538 and 25,336,778 issued and outstanding at September 30, 2023 and December 31, 2022, respectively	839,695		891,909


PARTNERS’ CAPITAL:
Common unitholders, 122,464,318 and 122,579,218 units issued and outstanding at September 30, 2023 and December 31, 2022, respectively	547,622		567,277
Accumulated other comprehensive income	6,479		6,114
Noncontrolling interests	357,877		310,162
Total partners’ capital	911,978		883,553
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	6,938,442	$	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 September 30,					Nine Months Ended September 30,
	2023		2022			2023		2022
REVENUES:
Offshore pipeline transportation	$	106,297	$	89,805		$	289,151	$	239,958
Soda and sulfur services	423,575		312,681			1,331,078		916,963
Marine transportation	80,220		77,795			240,789		209,889
Onshore facilities and transportation	197,526		240,967			541,874		708,110
Total revenues	807,618		721,248			2,402,892		2,074,920
COSTS AND EXPENSES:
Onshore facilities and transportation product costs	171,142		213,680			469,627		630,985
Onshore facilities and transportation operating costs	17,648		17,697			52,867		50,276
Marine transportation operating costs	53,371		63,074			162,955		165,726
Soda and sulfur services operating costs	344,963		235,308			1,123,850		699,847
Offshore pipeline transportation operating costs	23,651		25,410			71,515		74,785
General and administrative	16,770		17,038			48,253		52,825
Depreciation, depletion and amortization	68,379		73,946			209,966		217,125
Gain on sale of asset	—		—			—		(40,000)

Total costs and expenses	695,924		646,153			2,139,033		1,851,569
OPERATING INCOME	111,694		75,095			263,859		223,351
Equity in earnings of equity investees	17,242		13,236			49,606		40,252
Interest expense	(61,580)		(57,710)			(184,057)		(168,773)
Other expense	—		(21,388)			(1,812)		(10,758)
Income from operations before income taxes	67,356		9,233		—	127,596		84,072
Income tax expense	(574)		(660)			(1,748)		(1,535)


NET INCOME	66,782		8,573			125,848		82,537
Net income attributable to noncontrolling interests	(8,712)		(5,188)			(20,078)		(18,612)
Net income attributable to redeemable noncontrolling interests	—		—			—		(30,443)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	58,070	$	3,385		$	105,770	$	33,482
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(22,308)		(18,684)			(69,220)		(56,052)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS	$	35,762	$	(15,299)		$	36,550	$	(22,570)
NET INCOME (LOSS) PER COMMON UNIT (Note 12):


Basic and Diluted	$	0.29	$	(0.12)		$	0.30	$	(0.18)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	122,521		122,579			122,559		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

(In thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income	$	66,782	$	8,573	$	125,848	$	82,537
Other comprehensive income:
Decrease in benefit plan liability	122		122		365		365
Total Comprehensive income	66,904		8,695		126,213		82,902
Comprehensive income attributable to noncontrolling interests	(8,712)		(5,188)		(20,078)		(18,612)
Comprehensive income attributable to redeemable noncontrolling interests	—		—		—		(30,443)
Comprehensive income attributable to Genesis Energy, L.P.	$	58,192	$	3,507	$	106,135	$	33,847

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 Interests		Accumulated Other Comprehensive Income		Total
Partners’ capital, June 30, 2023	122,579	$	531,291	$	334,225	$	6,357	$	871,873
Repurchase of Class A common units	(115)	(1,044)		—		—		(1,044)
Net income	—	58,070		8,712		—		66,782
Cash distributions to partners	—	(18,387)		—		—		(18,387)
Cash distributions to noncontrolling interests	—	—		(10,980)		—		(10,980)
Cash contributions from noncontrolling interests	—	—		25,920		—		25,920
Other comprehensive income	—	—		—		122		122
Distributions and returns attributable to Class A Convertible Preferred unitholders	—	(22,308)		—		—		(22,308)


Partners’ capital, September 30, 2023	122,464	$	547,622	$	357,877	$	6,479	$	911,978

	Number of Common Units	Partners’ Capital		Noncontrolling Interests		Accumulated Other Comprehensive Loss		Total
Partners’ capital, June 30, 2022	122,579	$	596,059	$	299,846	$	(5,364)	$	890,541
Net income	—	3,385		5,188		—		8,573
Cash distributions to partners	—	(18,387)		—		—		(18,387)

Cash distributions to noncontrolling interests	—	—		(6,324)		—		(6,324)
Cash contributions from noncontrolling interests	—	—		10,440		—		10,440
Other comprehensive income	—	—		—		122		122
Distributions to Class A Convertible Preferred unitholders	—	(18,684)		—		—		(18,684)
Partners’ capital, September 30, 2022	122,579	$	562,373	$	309,150	$	(5,242)	$	866,281


	Number of Common Units	Partners’ Capital		Noncontrolling Interests		Accumulated Other Comprehensive Income		Total
Partners’ capital, December 31, 2022	122,579	$	567,277	$	310,162	$	6,114	$	883,553
Repurchase of Class A common units	(115)	(1,044)		—		—		(1,044)
Net income	—	105,770		20,078		—		125,848
Cash distributions to partners	—	(55,161)		—		—		(55,161)

Cash distributions to noncontrolling interests	—	—		(33,203)		—		(33,203)
Cash contributions from noncontrolling interests	—	—		60,840		—		60,840
Other comprehensive income	—	—		—		365		365
Distributions and returns attributable to Class A Convertible Preferred unitholders	—	(69,220)		—		—		(69,220)


Partners’ capital, September 30, 2023	122,464	$	547,622	$	357,877	$	6,479	$	911,978

	Number of Common Units	Partners’ Capital		Noncontrolling Interests		Accumulated Other Comprehensive Loss		Total
Partners’ capital, December 31, 2021	122,579	$	641,313	$	294,746	$	(5,607)	$	930,452
Net income	—	33,482		18,612		—		52,094
Cash distributions to partners	—	(55,161)		—		—		(55,161)
Adjustment to valuation of noncontrolling interest in subsidiary	—	(1,209)		1,209		—		—
Cash distributions to noncontrolling interests	—	—		(24,656)		—		(24,656)
Cash contributions from noncontrolling interests	—	—		19,239		—		19,239
Other comprehensive income	—	—		—		365		365
Distributions to Class A Convertible Preferred unitholders	—	(56,052)		—		—		(56,052)
Partners’ capital, September 30, 2022	122,579	$	562,373	$	309,150	$	(5,242)	$	866,281

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

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine Months Ended September 30,
	2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	125,848	$	82,537
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	209,966		217,125

Gain on sale of asset	—		(40,000)

Amortization and write-off of debt issuance costs, premium and discount	8,206		7,110


Equity in earnings of investments in equity investees	(49,606)		(40,252)
Cash distributions of earnings of equity investees	48,625		41,496
Non-cash effect of long-term incentive compensation plans	15,236		10,835
Deferred and other tax liabilities	925		1,010
Unrealized losses on derivative transactions	17,721		15,726
Cancellation of debt income	—		(8,619)
Other, net	15,839		14,203
Net changes in components of operating assets and liabilities (Note 15)	3,604		(48,576)
Net cash provided by operating activities	396,364		252,595
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(395,768)		(303,789)
Cash distributions received from equity investees - return of investment	19,600		14,737
Investments in equity investees	(4,463)		(5,441)


Proceeds from asset sales	307		40,281
Other, net	4,332		—
Net cash used in investing activities	(375,992)		(254,212)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	829,776		697,000
Repayments on senior secured credit facility	(836,776)		(625,800)
Net proceeds from issuance of Alkali senior secured notes (Note 10)	—		408,000
Redemption of redeemable noncontrolling interests (Note 11)	—		(288,629)
Proceeds from issuance of 2030 Notes (Note 10)	500,000		—
Repayment of senior unsecured notes (Note 10)	(341,135)		(72,241)
Debt issuance costs	(14,675)		(6,019)
Contributions from noncontrolling interests	60,840		19,239
Distributions to noncontrolling interests	(33,203)		(24,656)
Distributions to common unitholders	(55,161)		(55,161)
Distributions to Class A Convertible Preferred unitholders	(71,333)		(56,052)
Redemption of Class A Convertible Preferred Units (Note 11)	(50,000)		—
Repurchase of Class A common units (Note 11)	(1,044)		—
Other, net	5,677		5,429
Net cash provided by (used in) financing activities	(7,034)		1,110
Net increase (decrease) in cash, cash equivalents and restricted cash	13,338		(507)
Cash, cash equivalents and restricted cash at beginning of period	26,567		24,992
Cash, cash equivalents and restricted cash at end of period	$	39,905	$	24,485

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 of Mexico, Wyoming and in the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers and industrial and commercial enterprises. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (our “Alkali Business”), refinery-related plants, storage tanks and terminals, railcars, barges and other vessels and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.

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

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

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

•Onshore facilities and transportation, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum 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.

Basis of Presentation and Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its 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 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, 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

We are currently evaluating new accounting pronouncements that have been issued, but are not yet effective. At this time, they are not expected to have a material impact on our financial positions or results of operations.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3. Revenue Recognition

Revenue from Contracts with Customers

The following tables reflect the disaggregation of our revenues by major category for the three months ended September 30, 2023 and 2022, respectively:


	Three Months Ended September 30, 2023
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	106,297	$	—	$	80,220	$	16,769	$	203,286
Product Sales	—		399,329		—		180,757		580,086
Refinery Services	—		24,246		—		—		24,246
	$	106,297	$	423,575	$	80,220	$	197,526	$	807,618


	Three Months Ended September 30, 2022
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated
Fee-based revenues	$	89,805	$	—	$	77,795	$	20,177	$	187,777
Product Sales	—		290,620		—		220,790		511,410
Refinery Services	—		22,061		—		—		22,061
	$	89,805	$	312,681	$	77,795	$	240,967	$	721,248

The following tables reflect the disaggregation of our revenues by major category for the nine months ended September 30, 2023 and 2022, respectively:


	Nine Months Ended September 30, 2023
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	289,151	$	—	$	240,789	$	44,850	$	574,790
Product Sales	—		1,262,454		—		497,024		1,759,478
Refinery Services	—		68,624		—		—		68,624
	$	289,151	$	1,331,078	$	240,789	$	541,874	$	2,402,892


	Nine Months Ended September 30, 2022
	Offshore Pipeline Transportation		Soda and Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	239,958	$	—	$	209,889	$	54,280	$	504,127
Product Sales	—		837,335		—		653,830		1,491,165
Refinery Services	—		79,628		—		—		79,628
	$	239,958	$	916,963	$	209,889	$	708,110	$	2,074,920

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Contract Assets and Liabilities

The table below depicts our contract asset and liability balances at December 31, 2022 and September 30, 2023:


	Contract Assets		Contract Liabilities
	Other Assets, net of amortization		Accrued Liabilities		Other Long-Term Liabilities
Balance at December 31, 2022	$	—	$	2,087	$	64,478
Balance at September 30, 2023	181		5,127		95,213

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 September 30, 2023. However, we are permitted to utilize the following exemptions:

1)Performance obligations that are part of a contract with an expected duration of one year or less;

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

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

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

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


	Offshore Pipeline Transportation		Onshore Facilities and Transportation
Remainder of 2023	$	25,591	$	1,800
2024	102,998		1,800
2025	116,730		—
2026	86,706		—
2027	50,006		—
Thereafter	174,416		—
Total	$	556,447	$	3,600

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.

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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 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 September 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	14,992
Other Assets, net of amortization	400
Accounts payable - trade(1)	(228,106)
Accrued liabilities	(75,224)
Other long-term liabilities	(79,124)

Net Assets	$	—

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

Inventories principally relate to finished goods (soda ash) that have been supplied by current or former members of ANSAC. “Fixed assets, at cost” relate to leasehold improvements, and “Intangible assets, net of amortization” relate to 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 September 30, 2023		Nine Months Ended September 30, 2023
Revenues	$	92,399	$	321,853
Net Income Attributable to Genesis Energy, L.P.	5,373		10,644

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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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Pro forma consolidated financial operating results:
Revenues	$	807,618	$	813,647	$	2,402,892	$	2,396,773
Net Income Attributable to Genesis Energy, L.P.	58,070		8,758		105,770		44,126
Net Income (Loss) Attributable to Common Unitholders	35,762		(9,926)		36,550		(11,926)
Basic and diluted earnings (loss) per common unit:
As reported net income (loss) per common unit	$	0.29	$	(0.12)	$	0.30	$	(0.18)
Pro forma net income (loss) per common unit	$	0.29	$	(0.08)	$	0.30	$	(0.10)

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 (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 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 as well as our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease. Current and non-current lease liabilities are recorded within “Accrued liabilities” and “Other long-term liabilities,” respectively, on our Unaudited Condensed Consolidated Balance Sheets.

Lessor Arrangements

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

Operating Leases

During the three and nine months ended September 30, 2023 and 2022, we acted as a lessor in a revenue contract associated with the M/T American Phoenix, included in our marine transportation segment. Our lease revenues for this arrangement were $6.0 million and $17.7 million for the three and nine months ended September 30, 2023, respectively, and $1.8 million and $10.5 million for the three and nine months ended September 30, 2022, respectively.

The M/T American Phoenix is under contract through mid-2027, and for the remainder of 2023, 2024, 2025, 2026, and through the expiration of the contract in 2027, we expect to receive undiscounted cash flows from lease payments of $6.0 million, $25.9 million, $29.6 million, $30.7 million, and $15.2 million, respectively.

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6. Inventories

The major components of inventories were as follows:


	September 30, 2023		December 31, 2022
Petroleum products	$	—	$	56
Crude oil	31,495		6,673
Caustic soda	9,184		15,258
NaHS	12,676		7,085
Raw materials - Alkali Business	7,601		5,819
Work-in-process - Alkali Business	7,691		9,599
Finished goods, net - Alkali Business	41,205		18,772
Materials and supplies, net - Alkali Business	17,094		14,881

Total	$	126,946	$	78,143

Inventories are valued at the lower of cost or net realizable value. As of September 30, 2023 and December 31, 2022, the net realizable value of inventories were below cost by $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 these amounts.

Materials and supplies include chemicals, maintenance supplies and spare parts which will be consumed in the mining of trona ore and production of soda ash processes.

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7. Fixed Assets, Mineral Leaseholds and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following:


	September 30, 2023		December 31, 2022
Crude oil and natural gas pipelines and related assets	$	2,848,810	$	2,844,288
Alkali facilities, machinery and equipment	787,040		701,313
Onshore facilities, machinery and equipment	270,676		269,949
Transportation equipment	25,652		22,340
Marine vessels	1,020,568		1,017,087
Land, buildings and improvements	238,697		231,651
Office equipment, furniture and fixtures	24,749		24,271
Construction in progress(1)	991,151		712,971
Other	41,168		41,168
Fixed assets, at cost	6,248,511		5,865,038
Less: Accumulated depreciation	(1,925,879)		(1,768,465)
Net fixed assets	$	4,322,632	$	4,096,573

(1)Construction in progress primarily relates to our Granger Optimization Project, which is expected to be completed in the fourth quarter of 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:


	September 30, 2023		December 31, 2022
Mineral leaseholds	$	566,019	$	566,019
Less: Accumulated depletion	(24,153)		(20,897)
Mineral leaseholds, net of accumulated depletion	$	541,866	$	545,122

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	64,104	$	70,328	$	197,590	$	206,111
Depletion expense	1,107		896		3,256		2,830

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, 2022:


ARO liability balance, December 31, 2022	$	228,573
Accretion expense	9,316
Changes in estimate	3,915


Settlements	(68)

ARO liability balance, September 30, 2023	$	241,736

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At September 30, 2023 and December 31, 2022, $26.1 million and $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 September 30, 2023 and December 31, 2022 is included in “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheets.

Certain of our unconsolidated affiliates have AROs recorded at September 30, 2023 and December 31, 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.

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 September 30, 2023 and December 31, 2022, the unamortized excess cost amounts totaled $294.9 million and $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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Genesis’ share of operating earnings	$	20,908	$	16,802	$	60,304	$	50,950
Amortization of differences attributable to Genesis’ carrying value of equity investments	(3,566)		(3,566)		(10,698)		(10,698)
Net equity in earnings	$	17,242	$	13,236	$	49,606	$	40,252
Distributions received(1)	$	23,629	$	18,483	$	68,141	$	56,233

(1) Includes distributions attributable to the period and received during or within 15 days following 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,” and its pipeline and associated assets, the “Poseidon pipeline”) (which we own 64% of and is our most significant equity investment):


	September 30, 2023		December 31, 2022
BALANCE SHEETS DATA:
Assets
Current assets	$	21,428	$	27,878
Fixed assets, net	143,258		147,505
Other assets	16,629		13,419
Total assets	$	181,315	$	188,802
Liabilities and equity
Current liabilities	$	8,854	$	10,087
Other liabilities	240,553		236,813
Equity (Deficit)	(68,092)		(58,098)
Total liabilities and equity	$	181,315	$	188,802


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
STATEMENTS OF OPERATIONS DATA:
Revenues	$	43,316	$	38,322	$	123,462	$	104,891
Operating income	$	33,213	$	27,731	$	94,216	$	75,540
Net income	$	29,117	$	25,502	$	83,106	$	70,850

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Poseidon’s Revolving Credit Facility

Borrowings under Poseidon’s revolving credit facility, which was amended and restated on June 1, 2023 (the “June 2023 credit facility”), are primarily used to fund spending on capital projects. The June 2023 credit facility, which matures on June 1, 2027, is non-recourse to Poseidon’s owners and secured by 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.

9. Intangible Assets

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


	September 30, 2023						December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Offshore pipeline contract intangibles	158,101		67,956		90,145		158,101		61,715		96,386
Other	68,280		16,722		51,558		45,191		14,257		30,934
Total	$	226,381	$	84,678	$	141,703	$	203,292	$	75,972	$	127,320

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Amortization of intangible assets	$	3,069	$	2,575	$	8,747	$	7,740

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


Remainder of	2023	$	3,688
	2024	14,556
	2025	14,295
	2026	13,983
	2027	13,537

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10. Debt

Our obligations under debt arrangements consisted of the following:


	September 30, 2023						December 31, 2022
	Principal		Unamortized Premium, Discount and Debt Issuance Costs		Net Value		Principal		Unamortized Premium, Discount and Debt Issuance Costs		Net Value
Senior secured credit facility(1)	$	198,400	$	—	$	198,400	$	205,400	$	—	$	205,400
5.625% senior unsecured notes due 2024	—		—		—		341,135		1,249		339,886
6.500% senior unsecured notes due 2025	534,834		2,374		532,460		534,834		3,265		531,569
6.250% senior unsecured notes due 2026	339,310		1,929		337,381		339,310		2,481		336,829
8.000% senior unsecured notes due 2027	981,245		3,891		977,354		981,245		4,956		976,289
7.750% senior unsecured notes due 2028	679,360		6,496		672,864		679,360		7,621		671,739
8.875% senior unsecured notes due 2030	500,000		8,673		491,327		—		—		—
5.875% Alkali senior secured notes due 2042(2)	425,000		21,985		403,015		425,000		22,558		402,442
Total long-term debt	$	3,658,149	$	45,348	$	3,612,801	$	3,506,284	$	42,130	$	3,464,154

(1)Unamortized debt issuance costs associated with our senior secured credit facility (included in “Other Assets, net of amortization” on the Unaudited Condensed Consolidated Balance Sheets), were $6.3 million and $2.6 million as of September 30, 2023 and December 31, 2022, respectively.

(2)As of September 30, 2023, $8.7 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 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 a $850 million senior secured revolving credit facility. The new credit agreement matures on February 13, 2026, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, unless more than $150 million of our 2025 Notes remain outstanding as of June 30, 2025, in which case the new credit agreement matures on such date.

At September 30, 2023, the key terms for rates under our senior secured credit facility (which are dependent on our leverage ratio as defined in the new credit 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) 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) for such period plus (b) the Term SOFR Adjustment of 0.1% plus (c) the applicable margin. The applicable margin varies from 2.25% to 3.50% on Term SOFR borrowings and from 1.25% to 2.50% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At September 30, 2023, the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Term SOFR borrowings based on our leverage ratio.

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

•We pay a commitment fee on the unused portion of the 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 September 30, 2023, our commitment fee rate on the unused committed amount was 0.50%.

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

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At September 30, 2023, we had $198.4 million borrowed under our new credit agreement, with $21.7 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $9.5 million was outstanding at September 30, 2023. Due to the revolving nature of loans under our 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 senior secured credit facility at September 30, 2023 was $642.1 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 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. As of September 30, 2023, principal repayments totaling $65.3 million are due within the next five years, with the remaining quarterly principal repayments due thereafter through March 31, 2042. As of September 30, 2023, $8.7 million of the 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 by GA ORRI) to be held as collateral for future interest and principal payments as calculated and described in the agreement governing the Alkali senior secured notes. As of September 30, 2023, our liquidity reserve account 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 net proceeds from the issuance to fully redeem the outstanding Alkali Holdings preferred units (as defined and further discussed in Note 11) and utilized the remainder to repay a portion of the outstanding borrowings under our senior secured credit facility as well as fund our liquidity reserve account.

Senior Unsecured Note Transactions

On January 25, 2023, we issued $500.0 million in aggregate principal amount of 8.875% senior unsecured notes due April 15, 2030 (the “2030 Notes”). Interest payments are due April 15 and October 15 of each year with the initial interest payment due on October 15, 2023. The net proceeds were used to purchase $316.3 million of our 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 portion of the borrowings outstanding under our senior secured credit facility and for general partnership purposes.

On January 26, 2023, we issued a notice of redemption for the remaining principal of $24.8 million of our 2024 Notes and discharged the indebtedness with respect to the 2024 Notes on February 14, 2023.

Our $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, 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.

11. Partners’ Capital, Mezzanine Capital and Distributions

At September 30, 2023, our outstanding common units consisted of 122,424,321 Class A Common Units and 39,997 Class B Common Units. The Class A Common Units are traditional common units in us. The Class B Common Units are identical to the Class A Common Units and, accordingly, have voting and distribution rights equivalent to those of the Class A Common Units, and, in addition, the Class B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain circumstances, subject to certain exceptions. At September 30, 2023, we had 23,853,538 Class A Convertible Preferred Units outstanding, which are discussed below in further detail.

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In an effort to return capital to our investors, we announced a common equity repurchase program (the “Repurchase Program”) on August 8, 2023. The Repurchase Program authorizes the repurchase from time to time of up to 10% of our then outstanding Class A Common Units, or 12,253,922 units, via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. These repurchases may be made pursuant to a repurchase plan or plans that comply with Rule 10b5-1 under the Securities Exchange Act of 1934. The Repurchase Program will be reviewed no later than December 31, 2024 and may be suspended or discontinued at any time prior thereto. The Repurchase Program does not create an obligation for us to acquire a particular number of Class A Common Units and any Class A Common Units repurchased will be canceled. During the three months ended September 30, 2023, we repurchased and cancelled a total of 114,900 Class A Common Units at an average price of approximately $9.09 per unit for a total purchase price of $1.0 million, including commissions, which is reflected as a reduction to the carrying value of our “Partners’ Capital - Common unitholders” on our Unaudited Condensed Consolidated Balance Sheet.

Distributions

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


Distribution For	Date Paid	Per Unit Amount		Total Amount
2022
1st Quarter	May 13, 2022	$	0.15	$	18,387
2nd Quarter	August 12, 2022	$	0.15	$	18,387
3rd Quarter	November 14, 2022	$	0.15	$	18,387
4th Quarter	February 14, 2023	$	0.15	$	18,387
2023
1st Quarter	May 15, 2023	$	0.15	$	18,387
2nd Quarter	August 14, 2023	$	0.15	$	18,387
3rd Quarter(1)	November 14, 2023	$	0.15	$	18,370

(1)This distribution was declared in October 2023 and will be paid to unitholders of record as of October 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. We initially recognized our Class A Convertible Preferred Units at their issuance date fair value, net of issuance costs, as they were not redeemable and we did not have plans or expect any events that constitute a change of control in our partnership agreement. 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 and July 3, 2023, we entered into purchase agreements with the Class A Convertible Preferred unitholders whereby we redeemed a total of 1,483,240 Class A Convertible Preferred Units (the “Redeemed Units”) at an average purchase price of $33.71 per unit. The Redeemed Units had a carrying value of $35.20 per unit resulting in returns attributable to the Class A Convertible Preferred Units.

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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 $23.3 million and $71.3 million for the three and nine months ending September 30, 2023, respectively, and $18.7 million and $56.1 million, for the three and nine months ending September 30, 2022, respectively, due to Class A Convertible Preferred Unit distributions paid in the period (Class A Convertible Preferred Unit distributions are summarized in the table below). For the three and nine months ended September 30, 2023, Net Income Attributable to Genesis Energy L.P. was increased by $1.0 million and $2.1 million, respectively, due to returns attributable to the Class A Convertible Preferred Units accumulated in the period.

As of September 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 redemption first becomes probable and the date the units can first be redeemed.

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


Distribution For	Date Paid	Per Unit Amount		Total Amount





2022
1st Quarter	May 13, 2022	$	0.7374	$	18,684
2nd Quarter	August 12, 2022	$	0.7374	$	18,684
3rd Quarter	November 14, 2022	$	0.7374	$	18,684
4th Quarter	February 14, 2023	$	0.9473	$	24,002
2023
1st Quarter	May 15, 2023	$	0.9473	$	24,002
2nd Quarter(1)	August 14, 2023	$	0.9473	$	23,314
3rd Quarter(2)	November 14, 2023	$	0.9473	$	22,612

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

(2)This distribution was declared in October 2023 and will be paid to unitholders of record as of October 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 fourth quarter of 2023. In consideration 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.

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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 September 30, 2023, there were no Alkali Holdings preferred units outstanding.

Accounting for Redeemable Noncontrolling Interests

Classification

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

Initial and Subsequent Measurement

We recorded the Alkali Holdings preferred units at their issuance date fair value, net of issuance costs. The fair value 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 Attributable to Genesis Energy, L.P. for the nine months ended September 30, 2022 includes $30.4 million of adjustments, of which $10.0 million was allocated to the paid-in-kind (“PIK”) distributions, $1.9 million was attributable to redemption accretion value adjustments, and $18.5 million was attributable to a change in the Base Preferred Return Amount of the Alkali Holdings preferred units.

Noncontrolling Interests

We own a 64% membership interests in Cameron Highway Oil Pipeline Co. (“CHOPS”) and are the operator of its pipeline and associated assets (the “CHOPS pipeline”). We also own an 80% membership interest in Independence Hub, LLC. 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.

12. Net Income Per Common Unit

Basic net income (loss) per common unit is computed by dividing 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 net income (loss) per common unit calculation for the period being presented. The numerator is adjusted for distributions declared in the period, undeclared distributions that accumulated during the period, and any returns that accumulated in the period. For the three and nine months ended September 30, 2023 and 2022, the effect of the assumed conversion of all the outstanding Class A Convertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.

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The following table reconciles net income 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income attributable to Genesis Energy, L.P.	$	58,070	$	3,385	$	105,770	$	33,482
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(22,308)		(18,684)		(69,220)		(56,052)
Net income (loss) attributable to common unitholders	$	35,762	$	(15,299)	$	36,550	$	(22,570)

Weighted average outstanding units	122,521		122,579		122,559		122,579

Basic and diluted net income (loss) per common unit	$	0.29	$	(0.12)	$	0.30	$	(0.18)

13. Business Segment Information

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

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

•Onshore facilities and transportation, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum 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.

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.

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

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Segment information for the periods presented below was as follows:


	Offshore Pipeline Transportation		Soda and Sulfur Services		Onshore Facilities and Transportation		Marine Transportation		Total
Three Months Ended September 30, 2023
Segment Margin(1)	$	109,267	$	61,957	$	9,547	$	27,126	$	207,897
Capital expenditures(2)	$	149,489	$	36,502	$	6,696	$	12,496	$	205,183
Revenues:
External customers	$	101,985	$	425,913	$	199,500	$	80,220	$	807,618
Intersegment(3)	4,312		(2,338)		(1,974)		—		—
Total revenues of reportable segments	$	106,297	$	423,575	$	197,526	$	80,220	$	807,618
Three Months Ended September 30, 2022
Segment Margin(1)	$	91,402	$	80,067	$	9,442	$	15,279	$	196,190
Capital expenditures(2)	$	86,893	$	49,452	$	848	$	14,575	$	151,768
Revenues:
External customers	$	89,805	$	315,334	$	238,483	$	77,626	$	721,248
Intersegment(3)	—		(2,653)		2,484		169		—
Total revenues of reportable segments	$	89,805	$	312,681	$	240,967	$	77,795	$	721,248
Nine Months Ended September 30, 2023
Segment Margin(1)	$	300,505	$	217,319	$	21,242	$	78,578	$	617,644
Capital expenditures(2)	$	293,187	$	83,109	$	10,714	$	32,543	$	419,553
Revenues:
External customers	$	284,839	$	1,337,897	$	539,367	$	240,789	$	2,402,892
Intersegment(3)	4,312		(6,819)		2,507		—		—
Total revenues of reportable segments	$	289,151	$	1,331,078	$	541,874	$	240,789	$	2,402,892
Nine Months Ended September 30, 2022
Segment Margin(1)	$	281,286	$	219,143	$	27,496	$	44,989	$	572,914
Capital expenditures(2)	$	166,703	$	114,698	$	3,365	$	28,704	$	313,470
Revenues:
External customers	$	239,958	$	924,534	$	700,909	$	209,519	$	2,074,920
Intersegment(3)	—		(7,571)		7,201		370		—
Total revenues of reportable segments	$	239,958	$	916,963	$	708,110	$	209,889	$	2,074,920

(1)A reconciliation of Net income 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:


	September 30, 2023		December 31, 2022
Offshore pipeline transportation	$	2,497,570	$	2,290,488
Soda and sulfur services	2,573,777		2,358,086
Onshore facilities and transportation	1,146,639		981,354
Marine transportation	649,732		681,231
Other assets	70,724		54,833
Total consolidated assets	$	6,938,442	$	6,365,992

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income attributable to Genesis Energy, L.P.	$	58,070	$	3,385	$	105,770	$	33,482
Corporate general and administrative expenses	18,329		18,132		52,580		54,958
Depreciation, depletion, amortization and accretion	71,099		76,301		218,788		225,526
Interest expense	61,580		57,710		184,057		168,773
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income(1)	6,387		5,247		18,535		15,981
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)	(12,299)		26,295		17,721		16,083
Other non-cash items	(7,228)		(1,659)		(16,886)		(3,926)
Distribution from unrestricted subsidiaries not included in income(3)	—		—		—		32,000
Cancellation of debt income(4)	—		(3,881)		—		(8,618)
Loss on extinguishment of debt	—		293		1,812		794
Differences in timing of cash receipts for certain contractual arrangements(5)	11,385		13,775		33,519		38,482


Change in provision for leased items no longer in use	—		(68)		—		(599)
Redeemable noncontrolling interest redemption value adjustments(6)	—		—		—		30,443
Gain on sale of asset, net to our ownership interest(7)	—		—		—		(32,000)
Income tax expense	574		660		1,748		1,535
Total Segment Margin	$	207,897	$	196,190	$	617,644	$	572,914

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

(2)The three and nine months ended September 30, 2023 include unrealized gains of $12.3 million and unrealized losses of $17.7 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges). The three and nine months ended September 30, 2022 include unrealized losses of $1.3 million and unrealized gains of $2.5 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges), and unrealized losses of $25.0 million and $18.6 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.

(3)The nine months ended September 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.

(4)The three and nine months ended September 30, 2022 include income associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market of $3.9 million and $8.6 million, respectively.

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

(6)The nine months ended September 30, 2022 include PIK distributions, accretion on the redemption feature and valuation adjustments to the redemption feature as the associated preferred units were redeemed during the second quarter of 2022. Refer to Note 11 for details.

(7)On April 29, 2022, we sold our Independence 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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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 nine months ended September 30, 2022 do not include the activity related to ANSAC.

The transactions with related parties were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues:
Revenues from services and fees to Poseidon(1)	$	4,812	$	3,854	$	13,858	$	10,952

Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	495	$	495
Charges for services and product purchases from Poseidon(1)	6,797		268		8,834		777

(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 reflect what we could have 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 nine months ended September 30, 2023 include $2.5 million and $7.5 million, respectively, of fees we earned through the provision of services under that agreement. Our revenues for the three and nine months ended September 30, 2022 include $2.4 million and $7.3 million, respectively, of fees we earned through the provision of services under that agreement. At September 30, 2023 and December 31, 2022, Poseidon owed us $2.2 million and $2.4 million, respectively, for services rendered.

15. Supplemental Cash Flow Information

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


	Nine Months Ended September 30,
	2023		2022
(Increase) decrease in:
Accounts receivable	$	54,474	$	(170,635)
Inventories	(29,281)		(12,677)
Deferred charges	31,003		47,191
Other current assets	(4,571)		(4,717)
Increase (decrease) in:
Accounts payable	(31,006)		109,687
Accrued liabilities	(17,015)		(17,425)
Net changes in components of operating assets and liabilities	$	3,604	$	(48,576)

Payments of interest and commitment fees were $196.3 million and $189.2 million for the nine months ended September 30, 2023 and September 30, 2022, respectively.

We capitalized interest of $29.2 million and $11.2 million during the nine months ended September 30, 2023 and September 30, 2022, respectively.

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At September 30, 2023 and September 30, 2022, we had incurred liabilities for fixed and intangible asset additions totaling $121.4 million and $67.6 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 September 30, 2023 primarily relate to the capital expenditures associated with our offshore growth capital projects.

16. Derivatives

Crude Oil and Petroleum Products Hedges

We have exposure to commodity price changes related to our petroleum inventory and purchase commitments. We utilize derivative instruments (exchange-traded futures, options and swap contracts) to hedge our exposure to crude oil, fuel oil and other petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. We recognize any changes in the fair value of our derivative contracts as increases or decreases in “Onshore facilities and transportation product costs” in the Unaudited Condensed Consolidated Statements of Operations. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore, we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed.

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

Natural Gas Hedges

Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts, 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 “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.

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Balance Sheet Netting and Broker Margin Accounts

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset fair value amounts recorded for our exchange-traded derivative contracts against required margin funding in “Current Assets - Other” in our 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 September 30, 2023, we had a net broker receivable of approximately $14.5 million (consisting of initial margin of $7.2 million increased by $7.3 million variation margin). As of December 31, 2022, we had a net broker receivable of approximately $4.0 million (consisting of initial margin of $3.8 million increased by $0.2 million of variation margin). At September 30, 2023 and December 31, 2022, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

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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Outstanding Derivatives

At September 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)	398		192
Weighted average contract price per Bbl	$	80.23	$	82.51

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 Bbls)	59		33
Weighted average contract price per Bbl	$	84.75	$	90.34



Natural gas swaps:
Contract volumes (10,000 MMBtu)	—		1,261
Weighted average price differential per MMBtu	$	—	$	0.62
Natural gas futures:
Contract volumes (10,000 MMBtu)	180		1,294
Weighted average contract price per MMBtu	$	2.71	$	3.66









Natural gas options:
Contract volumes (10,000 MMBtu)	59		32
Weighted average premium received/paid	$	0.66	$	0.17






Bunker fuel futures:
Contract volumes (metric tons “MT”)	—		51,500
Weighted average price per MT	$	—	$	535.99
DOE diesel options:
Contract volumes (1,000 Gal)	—		1,050
Weighted average premium received/paid	$	—	$	0.27

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Fair Value of Derivative Assets and Liabilities

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


	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
		September 30, 2023		December 31, 2022
Asset Derivatives:
Natural Gas Swap (undesignated hedge)	Current Assets - Accounts receivable - trade, net	$	10,082	$	36,844
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other(1)	4,070		1,238
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	(4,070)		(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)	$	1,304	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	(1,304)		—
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—	$	—
Liability Derivatives:

Natural Gas Swap (undesignated hedge)	Current Liabilities -Accrued liabilities	$	(2,695)	$	(4,692)
Commodity derivatives - futures and put and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other(1)	$	(6,546)	$	(11,061)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	6,546		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)	$	(3,885)	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other(1)	3,885		—
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 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 Sheets. Corresponding changes in fair value are recognized in “Other income (expense)” in our Unaudited Condensed Consolidated Statement of Operations.

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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 $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 to include the fair value of the previously bifurcated amount at the Election Date. See Note 11 for additional information regarding our Class A Convertible Preferred Units and the Rate Reset Election.

Effect on Operating Results


		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs	$	(5,012)	$	2,085	$	(2,657)	$	1,549
Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, Soda and sulfur services operating costs	(3,379)		7,138		(15,673)		15,418
Total commodity derivatives		$	(8,391)	$	9,223	$	(18,330)	$	16,967

Natural Gas Swap	Soda and sulfur services operating costs	$	8,600	$	(489)	$	15,086	$	(2,181)

Preferred Distribution Rate Reset Election	Other income (expense)	$	—	$	(24,977)	$	—	$	(18,584)

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.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2023 and December 31, 2022.


	September 30, 2023						December 31, 2022
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Commodity derivatives:
Assets	$	5,374	$	10,082	$	—	$	1,238	$	36,844	$	—
Liabilities	$	(10,431)	$	(2,695)	$	—	$	(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 September 30, 2023.

See Note 16 for additional information on our derivative instruments.

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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 September 30, 2023 our senior unsecured notes had a carrying value of approximately $3.0 billion and a fair value of approximately $2.9 billion compared to a carrying value of $2.9 billion and fair value of approximately $2.7 billion at December 31, 2022. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement. At September 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.

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

•Forward Looking Statements

Overview

We reported Net Income Attributable to Genesis Energy, L.P. of $58.1 million during the three months ended September 30, 2023 (the “2023 Quarter”) compared to Net Income Attributable to Genesis Energy, L.P. of $3.4 million during the three months ended September 30, 2022 (the “2022 Quarter”).

Net Income Attributable to Genesis Energy, L.P. in the 2023 Quarter was impacted by an increase in Segment Margin of $11.7 million primarily due to increased volumes and activity in our offshore pipeline transportation segment 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 a decrease in depreciation, depletion and amortization expense of $5.6 million during the 2023 Quarter (see “Results of Operations” below for additional details). Additionally, the 2023 Quarter included $12.3 million in unrealized gains associated with the valuation of our commodity derivative transactions compared to unrealized losses of $1.3 million during the 2022 Quarter. The 2022 Quarter also included an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $25.0 million, which was included within “Other expense” on the Unaudited Condensed Consolidated Statement of Operations.

Cash flow from operating activities was $141.0 million for the 2023 Quarter compared to $94.3 million for the 2022 Quarter. The increase in cash flow from operating activities is primarily attributable to an increase in operating income associated with our operating segments (as discussed further below) and positive changes to working capital during the 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 $89.0 million for the 2023 Quarter, a decrease of $3.6 million, or 4%, from the 2022 Quarter primarily as a result of: (i) an increase in interest expense of $3.9 million (see “Results of Operations” below for additional details); (ii) an increase in cash payments to our Class A Convertible Preferred unitholders of $3.9 million; (iii) a decrease in income of $3.9 million associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market during the 2022 Quarter; and (iv) an increase in maintenance capital utilized of $2.8 million. These decreases to Available Cash before Reserves were partially offset by an increase in Segment Margin of $11.7 million from the 2022 Quarter to the 2023 Quarter, discussed in more detail below.

Segment Margin (as defined below in “Non-GAAP Financial Measures”) was $207.9 million for the 2023 Quarter, an increase of $11.7 million, or 6%, 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 Segment Margin.

Distribution to Unitholders

On August 14, 2023, we paid a distribution of $0.15 per common unit related to the second quarter of 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 August 14, 2023 to unitholders holders of record at the close of business July 31, 2023.

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In October 2023, we declared our quarterly distribution to our common unitholders of $0.15 per unit related to the 2023 Quarter. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per Class A Convertible Preferred Unit (or $3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable November 14, 2023 to unitholders of record at the close of business on October 31, 2023.

International Conflicts and Market Update

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 lasting impacts of international conflicts, such as the conflict in Israel and the war 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 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 these international conflicts, 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 2023 Quarter increased $86.4 million, or 12%, from the 2022 Quarter and our total costs and expenses as presented on the Unaudited Condensed Consolidated Statements of Operations increased $49.8 million, or 8%, between the two periods with an overall net increase to operating income of $36.6 million. The increase in our operating income during the 2023 Quarter is primarily due to increased volumes in our offshore pipeline transportation segment and higher day rates in our marine transportation segment. See further discussion below under “Segment Margin” regarding the activity in our individual operating segments. Additionally, the 2023 Quarter included $12.3 million in unrealized gains associated with the valuation of our commodity derivative transactions compared to unrealized losses of $1.3 million during the 2022 Quarter, which are included within operating costs. Lastly, we had lower depreciation, depletion, and amortization expense by $5.6 million 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 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”) decreased to $82.25 per barrel in the 2023 Quarter, as compared to $93.06 per barrel in the 2022 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 income and Available Cash before Reserves. We have limited our direct commodity price exposure related to crude oil and petroleum products through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. However, we do have some indirect exposure to certain changes in prices for oil and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when 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 volumes sold. We sell our products to an industry-diverse and worldwide customer base. Our sales prices are contracted at various times throughout the year and for different durations. Our sales prices for volumes sold internationally 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 nine months ended September 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 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 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 our ability to produce soda ash. Positive or negative changes to our revenue, through fluctuations in sales volumes or sales prices, can have a direct impact to Segment Margin, Net income and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, some of which 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 2023 Quarter, we had negative effects to our revenues (with a lesser impact to costs) relative to the 2022 Quarter due to lower pricing on our 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 approximately 98% of the volumes transported on our onshore crude pipelines, and refiners contracted for approximately 90% of the revenues from our marine transportation segment during the 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. 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 volatile commodity price environments. Given these facts, we do not expect changes in commodity prices to impact our Net income, Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

Additionally, changes in certain of our operating costs between the respective quarters, such as those associated with our 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Offshore pipeline transportation	$	109,267	$	91,402	$	300,505	$	281,286
Soda and sulfur services	61,957		80,067		217,319		219,143
Onshore facilities and transportation	9,547		9,442		21,242		27,496
Marine transportation	27,126		15,279		78,578		44,989
Total Segment Margin	$	207,897	$	196,190	$	617,644	$	572,914

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 Attributable to Genesis Energy, L.P. to total Segment Margin for the periods presented is as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net Income Attributable to Genesis Energy, L.P.	$	58,070	$	3,385	$	105,770	$	33,482
Corporate general and administrative expenses	18,329		18,132		52,580		54,958
Depreciation, depletion, amortization and accretion	71,099		76,301		218,788		225,526
Interest expense	61,580		57,710		184,057		168,773
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income(1)	6,387		5,247		18,535		15,981
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)	(12,299)		26,295		17,721		16,083
Other non-cash items	(7,228)		(1,659)		(16,886)		(3,926)
Distributions from unrestricted subsidiaries not included in income(3)	—		—		—		32,000
Cancellation of debt income(4)	—		(3,881)		—		(8,618)
Loss on debt extinguishment	—		293		1,812		794
Differences in timing of cash receipts for certain contractual arrangements(5)	11,385		13,775		33,519		38,482


Change in provision for leased items no longer in use	—		(68)		—		(599)
Redeemable noncontrolling interest redemption value adjustments(6)	—		—		—		30,443
Gain on sale of asset, net to our ownership interest(7)	—		—		—		(32,000)
Income tax expense	574		660		1,748		1,535
Total Segment Margin	$	207,897	$	196,190	$	617,644	$	572,914

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

(5)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.

(7)On April 29, 2022, we sold our Independence 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues	$	88,399	$	79,638	$	242,566	$	216,562
Offshore natural gas pipeline revenue, excluding non-cash revenues	15,188		13,141		44,611		35,649
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses	(17,424)		(19,860)		(53,238)		(57,383)
Distributions from unrestricted subsidiaries(1)	—		—		—		32,000
Distributions from equity investments(2)	23,104		18,483		66,566		54,458
Offshore pipeline transportation Segment Margin	$	109,267	$	91,402	$	300,505	$	281,286

Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS	307,045		197,583		266,974		198,067
Poseidon	310,817		282,583		304,771		262,222
Odyssey	60,830		88,112		62,119		95,160
GOPL(3)	3,033		7,578		2,471		7,047
Total crude oil offshore pipelines	681,725		575,856		636,335		562,496

Natural gas transportation volumes (MMBtus/day)	408,866		358,618		398,060		338,598

Volumetric Data net to our ownership interest(4):
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS	196,509		126,453		170,863		126,763
Poseidon	198,923		180,853		195,053		167,822
Odyssey	17,641		25,552		18,015		27,596
GOPL(3)	3,033		7,578		2,471		7,047
Total crude oil offshore pipelines	416,106		340,436		386,402		329,228

Natural gas transportation volumes (MMBtus/day)	115,203		114,671		112,710		108,673

(1)Offshore pipeline transportation Segment Margin for the nine months ended September 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 2023 and 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 throughout the year multiplied by the relevant throughput over the given year.

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Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Offshore pipeline transportation Segment Margin for the 2023 Quarter increased $17.9 million, or 20%, from the 2022 Quarter primarily due to higher crude oil and natural gas activity and volumes and less overall downtime during the 2023 Quarter. The increase in our volumes during the 2023 Quarter is primarily a result of the King’s Quay Floating Production System (“FPS”), which achieved first oil in the second quarter of 2022, and has since ramped up production levels reaching 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 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. The Argos FPS, which supports BP’s operated Mad Dog 2 field development, began producing in the second quarter of 2023 and achieved production levels of approximately 90,000 barrels of oil per day in the 2023 Quarter, with 100% of the volumes flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore. We expect to continue to benefit from King’s Quay FPS and Argos FPS volumes throughout 2023 and over their anticipated production profiles. In addition to these developments, activity in and around our Gulf of Mexico asset base continues to be robust, including incremental in-field drilling at existing fields that tie into our infrastructure. Lastly, the 2023 Quarter had less overall downtime as compared to the 2022 Quarter, which was primarily a result of no weather-related events and no significant planned producer downtime during the period.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Offshore pipeline transportation Segment Margin for the first nine months of 2023 increased $19.2 million, or 7%, from the first nine months of 2022 primarily due 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 nine months of volumes from King’s Quay, including its ramp in production to levels reaching approximately 130,000 barrels of oil equivalent per day during 2023. Additionally, the first nine 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 from the sale of its platform asset in 2022.

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Soda and Sulfur Services Segment

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Volumes sold:
NaHS volumes (Dry short tons “DST”)	27,325		29,441		81,501		97,243
Soda Ash volumes (short tons sold)	867,319		776,284		2,424,150		2,293,213
NaOH (caustic soda) volumes (DST)	18,229		23,186		58,751		65,983


Revenues (in thousands):
NaHS revenues, excluding non-cash revenues	$	36,360	$	42,821	$	116,568	$	136,633
NaOH (caustic soda) revenues	14,044		19,774		49,839		50,451
Revenues associated with Alkali Business(1)	350,121		228,414		1,098,951		651,105
Other revenues	1,142		2,263		3,915		6,716
Total external segment revenues, excluding non-cash revenues	$	401,667	$	293,272	$	1,269,273	$	844,905

Segment Margin (in thousands)	$	61,957	$	80,067	$	217,319	$	219,143

Average index price for NaOH per DST(2)	$	992	$	1,177	$	1,109	$	1,075

(1)See discussion above in “Results of Operations — Revenues and Costs and Expenses” regarding revenues associated with our Alkali Business.

(2)Source: IHS Chemical.

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Soda and sulfur services Segment Margin for the 2023 Quarter decreased $18.1 million, or 23%, from the 2022 Quarter primarily due to lower export pricing in our Alkali Business and lower NaHS and caustic soda sales volumes and pricing during the 2023 Quarter, which was partially offset by higher soda ash sales volumes in the period. The 2023 Quarter was impacted by a decline in export pricing as compared to the 2022 Quarter (as well as when compared to the first half of 2023) as a result of slowing global demand and a slower than anticipated re-opening of China’s economy combined with the anticipated ramp in new global supply entering the market. We expect this volatility and supply and demand dynamic to continue to impact our pricing in the fourth quarter of 2023. We successfully restarted our original Granger production facility on January 1, 2023 and expect to see first production from our expanded Granger facility in the fourth quarter of 2023, which represents an incremental 750,000 tons of lower cost annual production that we anticipate to ramp up to. As a result of restarting our original Granger facility and ramping up production to its original nameplate capacity of approximately 500,000 tons on an annual basis, we had higher soda ash sales volumes during the 2023 Quarter. Once we complete the Granger Optimization Project (“GOP”), we would expect these incremental sales volumes to have a more meaningful impact to our reported Segment Margin in subsequent quarters as we can better absorb the fixed cost structure at our Granger facility.

In our sulfur services business, we experienced a decrease in Segment Margin due to a decrease in NaHS sales volumes and pricing. NaHS sales volumes, when compared to the 2022 Quarter, decreased due to multiple factors, including a reduction in production volumes from a host refinery that partially converted its facility into a renewable diesel facility in the fourth quarter of 2022 and continued pressure on demand (that also negatively impacted prices) and timing delays in shipments, primarily in South America. In addition, the 2022 Quarter experienced robust NaHS sales volumes and pricing due to an increase in demand from our mining customers, primarily in South America, and due to our ability to leverage our multi-faceted supply and terminal sites in our sulfur services business to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges. NaHS production volumes and inventory levels during the 2023 Quarter returned to a more normalized level, as the unplanned operational and weather-related outages we experienced in the second quarter of 2023 were resolved.

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Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Soda and sulfur services Segment Margin for the first nine months of 2023 decreased $1.8 million, or 1%, from the first nine months of 2022 primarily due to lower NaHS and caustic soda sales volumes and pricing in our sulfur services business, which were mostly offset by higher domestic and export pricing and an increase in soda ash sales volumes in our Alkali Business during 2023. We successfully restarted our original Granger production facility on January 1, 2023 and ramped up the production to its original nameplate capacity of approximately 500,000 tons on an annual basis throughout the first nine months of 2023. Additionally, we had higher pricing on our domestic and export sales due to a strong supply and demand balance in the first half 2023, which weakened during the 2023 Quarter as noted above. These increases were 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 sulfur services business, we have experienced lower than expected production during 2023 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 second quarter of 2023 (which returned to normal operations 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, we have experienced continued pressure on demand primarily in South America, which has negatively impacted sales volumes and prices. In comparison, during the first nine 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, and due to our ability to leverage our multi-faceted supply and terminal sites in our sulfur services business to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges.

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. Through these assets we offer our customers a full suite of services, including the following as of September 30, 2023:

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

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

•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;

•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; 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Gathering, marketing, and logistics revenue	$	188,276	$	230,564	$	517,262	$	678,985
Crude oil pipeline tariffs and revenues	6,872		8,984		19,389		24,343

Crude oil and products costs, excluding unrealized gains and losses from derivative transactions	(170,857)		(214,004)		(469,253)		(631,720)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses	(17,246)		(17,104)		(51,762)		(49,446)
Other	2,502		1,002		5,606		5,334
Segment Margin	$	9,547	$	9,442	$	21,242	$	27,496

Volumetric Data (average barrels per day unless otherwise noted):
Onshore crude oil pipelines:
Texas	66,376		113,962		65,648		92,508
Jay	6,161		5,481		5,710		6,348
Mississippi	4,854		5,800		4,866		5,926
Louisiana(1)	60,973		127,827		70,843		103,195

Onshore crude oil pipelines total	138,364		253,070		147,067		207,977

Crude oil and petroleum products sales	23,703		25,613		23,006		23,860
Rail unload volumes	—		15,130		—		14,485

(1)Total daily volumes for the three and nine months ended September 30, 2023 include 42,622 and 34,720 Bbls/day, respectively, of intermediate refined products and 17,201 and 35,564 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily volumes for the three and nine months ended September 30, 2022 include 23,265 and 27,131 Bbls/day, respectively, of intermediate refined products and 87,656 and 62,172 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Onshore facilities and transportation Segment Margin for the 2023 Quarter increased $0.1 million, or 1%, from the 2022 Quarter primarily due to a favorable mix of terminal and pipelines volumes on our Baton Rouge corridor assets (as we get a higher contribution to Segment Margin on intermediate refined products moving through our assets) and higher volumetric gains on our pipelines during the 2023 Quarter. These increases were offset by a decrease in rail unload volumes in the 2023 Quarter. The 2022 Quarter had an increase in rail volumes as a result of our main customer sourcing volumes to replace international volumes that were impacted by certain geopolitical events 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 our customer’s refinery complex.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Onshore facilities and transportation Segment Margin for the first nine months of 2023 decreased $6.3 million, or 23%, from the first nine months of 2022. This decrease is primarily due to an overall decrease in activity on our Baton Rouge corridor assets, specifically our rail unload and pipeline volumes, and a decrease in volumes on our Texas pipeline system during the first nine months of 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 September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Revenues (in thousands):
Inland freight revenues	$	30,974		$	27,758		$	94,067		$	74,990
Offshore freight revenues	29,459			20,878			83,341			63,769
Other rebill revenues(1)	19,787			29,159			63,381			71,130
Total segment revenues	$	80,220		$	77,795		$	240,789		$	209,889

Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (in thousands)	$	53,094		$	62,516		$	162,211		$	164,900

Segment Margin (in thousands)	$	27,126		$	15,279		$	78,578		$	44,989

Fleet Utilization:(2)
Inland Barge Utilization	99.4		%	100.0		%	99.8		%	97.3		%
Offshore Barge Utilization	98.5		%	94.0		%	97.6		%	96.1		%

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

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

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Marine transportation Segment Margin for the 2023 Quarter increased $11.8 million, or 78%, from the 2022 Quarter. This increase is primarily attributable to higher day rates in our inland and offshore businesses, including the M/T American Phoenix, during the 2023 Quarter. Demand for our barge services to move intermediate and refined products 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 and long lead times for construction) as well as the retirement of older vessels in the market. These factors have also contributed to an overall increase in spot and term rates for our services. Additionally, the M/T American Phoenix is under contract for the remainder of 2023 with an investment grade customer at a more favorable rate than 2022, and during the 2023 Quarter, we entered into a new three-and-a-half-year contract starting in January of 2024 with a credit-worthy counterparty at the highest day rate we have received since we first purchased the vessel in 2014.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Marine transportation Segment Margin for the first nine months of 2023 increased $33.6 million, or 75%, from the first nine months of 2022. This increase is primarily attributable to an increase in overall day rates in our inland and offshore business, including the M/T American Phoenix. In addition, we have continued to see 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 the market have contributed the increase in day rates discussed above.

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Other Costs, Interest and Income Taxes

General and administrative expenses


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	12,724	$	13,104	$	37,220	$	38,060
Segment	1,016		904		2,936		2,758
Long-term incentive compensation expense	3,030		2,091		7,992		5,126
Third party costs related to business development activities and growth projects	—		939		105		6,881
Total general and administrative expenses	$	16,770	$	17,038	$	48,253	$	52,825

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Total general and administrative expenses for the 2023 Quarter decreased by $0.3 million from the 2022 Quarter primarily due to lower third party costs related to business development activities and growth projects and lower overall corporate expenses. These decreases were partially offset by an increase in our long-term incentive compensation expense during the 2023 Quarter as a result of the assumptions used to value our outstanding awards.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Total general and administrative expenses for the first nine months of 2023 decreased by $4.6 million primarily due to lower third party costs related to business development activities and growth projects as the first nine months of 2022 included costs associated with the issuance of our Alkali senior secured notes and related sale of the ORRI Interests, as well as costs associated with the divestiture of our previously owned Independence Hub platform. These decreases were partially offset by an increase in our long-term compensation expense during the first nine months of 2023.

Depreciation, depletion and amortization expense


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Depreciation and depletion expense	$	65,211	$	71,224	$	200,846	$	208,941
Amortization expense	3,168		2,722		9,120		8,184
Total depreciation, depletion and amortization expense	$	68,379	$	73,946	$	209,966	$	217,125

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Total depreciation, depletion and amortization expense for the 2023 Quarter decreased by $5.6 million from the 2022 Quarter. This 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 as well as certain of our assets becoming fully depreciated throughout the period. This decrease was partially offset by our continued growth and maintenance capital expenditures and placing new assets into service throughout the period and subsequent to the period ended September 30, 2022.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Total depreciation, depletion and amortization expense for the first nine months of 2023 decreased by $7.2 million from the first nine 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 period ended September 30, 2022.

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Interest expense, net


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)				(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	5,970	$	3,008	$	15,461	$	6,635
Interest expense, Alkali senior secured notes	6,243		6,187		18,727		9,292
Interest expense, senior unsecured notes	57,874		51,641		172,059		157,700
Amortization of debt issuance costs, premium and discount	2,393		2,166		7,033		6,317
Capitalized interest	(10,900)		(5,292)		(29,223)		(11,171)
Interest expense, net	$	61,580	$	57,710	$	184,057	$	168,773

Three Months Ended September 30, 2023 Compared with Three Months Ended September 30, 2022

Interest expense, net for the 2023 Quarter increased by $3.9 million primarily due to an increase in interest on our senior secured credit facility and an increase in interest on our senior unsecured notes. The increase in interest expense associated with our senior secured credit facility is primarily due to an increase in the SOFR rate, which is one of the main components of our interest rate, compared to the 2022 Quarter, and a higher average outstanding indebtedness during the 2023 Quarter. The increase in interest expense associated with our senior unsecured notes is primarily related to the issuance of our 2030 Notes in January 2023, which have a higher principal and interest rate than the 2024 Notes that were redeemed in January 2023 (see further discussion in Note 10 in our Unaudited Condensed Consolidated Financial Statements). This increase was partially offset by higher capitalized interest during the 2023 Quarter as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction projects.

Nine Months Ended September 30, 2023 Compared with Nine Months Ended September 30, 2022

Net interest expense for the first nine months of 2023 increased by $15.3 million due to 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 increase in interest expense associated with our senior secured credit facility is primarily due to an increase in the SOFR rate, which is one of the main components of our interest rate, compared to the first nine months of 2022, and higher outstanding indebtedness during the first nine months of 2023. The increase in interest expense associated with our senior unsecured notes was primarily related to the issuance of our 2030 Notes in January 2023, which have a higher principal and interest rate than the 2024 Notes that were redeemed in January 2023. This increase was partially offset by higher capitalized interest during the first nine months of 2023 as a result of our increased capital expenditures associated with the GOP and our offshore growth capital construction 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 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 senior secured revolving credit facility. The new credit agreement matures on February 13, 2026, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, unless more than $150 million of our 2025 Notes remain outstanding as of June 30, 2025, in which case the 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 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 our capital structure and lower our cost of capital, provide us additional flexibility under our 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, July 3, 2023 and October 2, 2023, we entered into purchase agreements with the Class A Convertible Preferred unitholders whereby we redeemed a total of 2,224,860 Class A Convertible Preferred Units at an average 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%, has allowed us to lower our overall cost of capital.

In an effort to return capital to our investors, we announced the Repurchase Program on August 8, 2023. The Repurchase Program authorizes the repurchase from time to time of up to 10% of our then outstanding Class A Common Units, or 12,253,922 units, via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. These repurchases may be made pursuant to a repurchase plan or plans that comply with Rule 10b5-1 under the Securities Exchange Act of 1934. The Repurchase Program will be reviewed no later than December 31, 2024 and may be suspended or discontinued at any time prior thereto. The Repurchase Program does not create an obligation for us to acquire a particular number of Class A Common Units and any Class A Common Units repurchased will be canceled. During the three months ended September 30, 2023, we repurchased and cancelled a total of 114,900 Class A Common Units at an average price of approximately $9.09 per unit for a total purchase price of $1.0 million, including commissions, which is reflected as a reduction to the carrying value of our “Partners’ Capital - Common unitholders” on our Unaudited Condensed Consolidated Balance Sheet. We anticipate funding any future repurchase activity with a portion of our cash flows from operations and liquidity available under our senior secured credit facility.

The successful completion of our new credit agreement (including its extended maturity and increased borrowing capacity), the refinancing of our previously held 2024 Notes, and the continued efforts to simplify our capital structure and lower our overall cost of capital has extended our debt maturity runway and has provided us a significant amount of liquidity to utilize for funding the remaining growth capital expenditures associated with the Granger expansion and our offshore growth projects (as discussed in further detail below), amongst other things. The available borrowing capacity under our senior secured credit facility at September 30, 2023 is $642.1 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 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.

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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;

•interest payments related to outstanding debt;

•asset retirement obligations;

•quarterly cash distributions to our preferred and common 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.

At September 30, 2023, our debt totaled approximately $3.7 billion, consisting of $198.4 million outstanding under our senior secured credit facility (including $21.7 million borrowed under the inventory sublimit tranche), $3.0 billion of senior unsecured notes and $425.0 million of Alkali senior secured notes (of which $8.7 million is current), which are secured by the ORRI Interests. Our senior unsecured notes balance is comprised of $534.8 million carrying amount due October 2025, $339.3 million carrying amount due May 2026, $981.2 million carrying value due January 2027, $679.4 million carrying amount due February 2028 and $500.0 million 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. 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 crude oil in the same month in which we 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 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 domestically and internationally. When we experience any differences in timing between the extraction, processing and sales of this trona or Alkali products, including the logistics and transportation to our customers, this could impact the cash requirements for these activities.

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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 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 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 15 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities during the 2023 Quarter and 2022 Quarter.

Net cash flows provided by our operating activities for the nine months ended September 30, 2023 were $396.4 million compared to $252.6 million for the nine months ended September 30, 2022. The increase in cash flows from operating activities is primarily attributable to changes in working capital between the two periods and our reported increase in Segment Margin during 2023 relative to Segment Margin in 2022 (which included the $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 and distributions we pay to our common and 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:


	Nine Months Ended September 30,
	2023		2022
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets	$	3,758	$	5,127
Soda and sulfur services assets	49,866		49,965
Marine transportation assets	26,870		28,704
Onshore facilities and transportation assets	5,602		1,715
Information technology systems and corporate assets	789		5,012
Total maintenance capital expenditures	86,885		90,523
Growth capital expenditures:
Offshore pipeline transportation assets(1)	285,291		157,785
Soda and sulfur services assets	33,243		64,733
Marine transportation assets	5,673		—
Onshore facilities and transportation assets	4,787		—
Information technology systems and corporate assets	7,834		6,960
Total growth capital expenditures	336,828		229,478
Total capital expenditures for fixed and intangible assets	423,713		320,001




Capital expenditures related to equity investees	4,463		5,441
Total capital expenditures	$	428,176	$	325,442

(1)Growth capital expenditures in our offshore pipeline transportation segment for 2023 and 2022 represent 100% of the costs incurred.

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Growth Capital Expenditures

On September 23, 2019, we announced the GOP. The anticipated completion date of the project is the fourth quarter of 2023. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.

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 approximately 160,000 barrels per day. In conjunction with these agreements, we expect total capital expenditures of approximately $550 million net to our ownership 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 senior secured credit facility and our recurring cash flows generated from operations.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred during 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 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 August 14, 2023, we paid a distribution to our common unitholders of $0.15 per common unit related to the second quarter of 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 August 14, 2023 to unitholders holders of record at the close of business July 31, 2023.

In October 2023, we declared our quarterly distribution to our common unitholders of $0.15 per common unit totaling $18.4 million with respect to the 2023 Quarter and a distribution of $0.9473 per Class A Convertible Preferred Unit (or $3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on November 14, 2023 to unitholders of record at the close of business on October 31, 2023.

Guarantor Summarized Financial Information

Our $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 10 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 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.

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

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


Balance Sheets	Genesis Energy, L.P. and Guarantor Subsidiaries
	September 30, 2023
	(in thousands)
ASSETS:
Current assets	$	1,053,362
Fixed assets and mineral leaseholds, net	3,805,414
Non-current assets(1)	981,481

LIABILITIES AND CAPITAL:(2)
Current liabilities	969,571
Non-current liabilities	3,740,606
Class A Convertible Preferred Units	839,695


Statement of Operations	Genesis Energy, L.P. and Guarantor Subsidiaries
	Nine Months Ended September 30, 2023
	(in thousands)
Revenues(3)	$	2,301,638
Operating costs	2,093,566
Operating income	208,072
Income before income taxes	91,109
Net income(2)	89,362

Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units	(69,220)
Net income attributable to common unitholders	$	20,142

(1)Excluded from non-current assets in the table above are $10.9 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of September 30, 2023.

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

(3)Excluded from revenues in the table above are $2.1 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the nine months ended September 30, 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 September 30,
	2023		2022
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	58,070	$	3,385
Income tax expense	574		660
Depreciation, depletion, amortization and accretion	71,099		76,301

Plus (minus) Select Items, net	(767)		45,583
Maintenance capital utilized(1)	(17,200)		(14,400)
Cash tax expense	(200)		(250)
Distributions to preferred unitholders	(22,612)		(18,684)



Available Cash before Reserves	$	88,964	$	92,595

(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 2023 Quarter and 2022 Quarter were $33.6 million and $44.3 million, respectively.

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 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.


		Three Months Ended September 30,
		2023		2022
		(in thousands)
I.	Applicable to all Non-GAAP Measures
	Differences in timing of cash receipts for certain contractual arrangements(1)	$	11,385	$	13,775


	Certain non-cash items:
	Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)	(12,299)		26,295
	Loss on debt extinguishment	—		293
	Adjustment regarding equity investees(3)	6,387		5,247
	Other	(7,228)		(1,659)
	Sub-total Select Items, net	(1,755)		43,951
II.	Applicable only to Available Cash before Reserves
	Certain transaction costs	—		939

	Other	988		693
	Total Select Items, net(4)	$	(767)	$	45,583

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(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 2023 Quarter includes unrealized gains of $12.3 million from the valuation of our commodity derivative transactions (excluding fair value hedges). The 2022 Quarter includes unrealized losses of $1.3 million from the valuation of our commodity derivative transactions (excluding fair value hedges) and an unrealized loss of $25.0 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.

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

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

Non-GAAP Financial Measures

General

To help evaluate our business, 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 attributable Genesis Energy, L.P. to total Segment Margin is also included in our segment disclosure in Note 13 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 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 directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other 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.

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 (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 attributable to Genesis Energy, L.P. to total Segment Margin is included in our segment disclosure in Note 13 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;

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(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. 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, (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.

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

•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, 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;

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•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, 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 war in Ukraine and the conflict in Israel), global pandemics, 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.

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 16 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures

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

There were no changes during the 2023 Quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 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, 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 2023 Quarter.

The table below sets forth information regarding our purchases of Class A Common Units during the 2023 Quarter pursuant to the Repurchase Program (see N ote 11 to our Unaudited Condensed Consolidated Financial Statements) announced on August 8, 2023.


Period	Total number of units repurchased	Average price per unit		Total number of units purchased as part of publicly announced plans	Maximum number of units that may yet be purchased under the plan
July 1 - July 31, 2023	—	$	—	—	—
August 1 - August 31, 2023	104,900	$	8.96	104,900	12,149,092
September 1 - September 30, 2023	10,000	$	10.15	10,000	12,139,092
Total	114,900			114,900

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’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).
	3.3	Sixth Amended and Restated Credit Agreement, dated as 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 10.1 to the Company’s Current Report on Form 8-K filed on February 23, 2023, File No. 001-12295).
	3.4	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.5	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.6	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’s Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	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’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).



	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.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	95	Mine Safety Disclosures.
	101.INS	XBRL Instance Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
	101.SCH	XBRL Schema Document.
	101.CAL	XBRL Calculation Linkbase Document.
	101.LAB	XBRL Label Linkbase Document.
	101.PRE	XBRL Presentation Linkbase Document.
	101.DEF	XBRL Definition Linkbase Document.
	104	Cover Page Interactive Data File (formatted as Inline XBRL).


*			Filed herewith

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SIGNATURES

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


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

			By:			GENESIS ENERGY, LLC, as General Partner


Date:	November 2, 2023	By:	/s/ KRISTEN O. JESULAITIS
			Kristen O. Jesulaitis
			Chief Financial Officer
			(Duly Authorized Officer)