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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 June 30, 2025
OR
☐ 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 | , | TX |  |  |  | 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 | x |  | 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 July 30, 2025.

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GENESIS ENERGY, L.P.
TABLE OF CONTENTS

|  | Page
| PART I. FINANCIAL INFORMATION |
Item 1. | Financial Statements | 3
| Condensed Consolidated Balance Sheets as of June 30, 2025 (unaudited) and December 31, 2024 | 3
| Unaudited Condensed Consolidated Statements of Operations | 4
| Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) | 5
| Unaudited Condensed Consolidated Statements of Partners’ Capita l (Deficit) | 6
| Unaudited Condensed Consolidated Statements of Cash Flows | 7
| Notes to Unaudited Condensed Consolidated Financial Statements | 8
| 1. Organization and Basis of Presentation and Consolidation | 8
| 2. Recent Accounting Developments | 9
| 3. Revenue Recognition | 9
| 4. Discontinued Operations | 10
| 5. Lease Accounting | 12
| 6. Inventories | 13
| 7. Fixed Assets and Asset Retirement Obligations | 14
| 8. Equity Investees | 14
| 9. Intangible Assets | 15
| 10. Debt | 16
| 11. Partners’ Capital (Deficit), Mezzanine Capital and Distributions | 17
| 12. Net Income (Loss) Per Common Unit | 19
| 13. Business Segment Information | 20
| 14. Transactions with Related Parties | 23
| 15. Supplemental Cash Flow Information | 23
| 16. Derivatives | 24
| 17. Fair-Value Measurements | 27
| 18. Commitments and Contingencies | 27
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 28
Item 3. | Quantitative and Qualitative Disclosures about Market Risk | 48
Item 4. | Controls and Procedures | 48
| PART II. OTHER INFORMATION |
Item 1. | Legal Proceedings | 50
Item 1A. | Risk Factors | 50
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 50
Item 3. | Defaults upon Senior Securities | 50
Item 4. | Mine Safety Disclosures | 50
Item 5. | Other Information | 50
Item 6. | Exhibits | 51
SIGNATURES | 52

2

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
GENESIS ENERGY, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except units)

| June 30, 2025 |  | December 31, 2024
| (unaudited) |  |
ASSETS |  |  |
CURRENT ASSETS: |  |  |
Cash and cash equivalents | $ | 4,452 |  |  | $ | 7,352 |
Accounts receivable - trade, net | 499,590 |  |  | 479,504 |
Inventories | 58,184 |  |  | 37,782 |
Other | 25,082 |  |  | 18,789 |
Current assets held for discontinued operations | — |  |  | 368,307 |
Total current assets | 587,308 |  |  | 911,734 |
FIXED ASSETS, at cost | 5,342,394 |  |  | 5,280,860 |
Less: Accumulated depreciation | (1,816,766) |  |  | (1,740,974) |
Net fixed assets | 3,525,628 |  |  | 3,539,886 |
EQUITY INVESTEES | 228,682 |  |  | 240,368 |
INTANGIBLE ASSETS, net of amortization | 80,449 |  |  | 85,287 |
GOODWILL | 301,959 |  |  | 301,959 |
RIGHT OF USE ASSETS, net | 58,605 |  |  | 65,739 |
OTHER ASSETS | 55,907 |  |  | 53,606 |
NON-CURRENT ASSETS - held for discontinued operations | — |  |  | 1,839,113 |
TOTAL ASSETS | $ | 4,838,538 |  |  | $ | 7,037,692 |
LIABILITIES AND CAPITAL |  |  |
CURRENT LIABILITIES: |  |  |
Accounts payable - trade | $ | 414,436 |  |  | $ | 388,245 |
Accrued liabilities | 207,469 |  |  | 254,202 |
Current liabilities held for discontinued operations | — |  |  | 216,308 |
Total current liabilities | 621,905 |  |  | 858,755 |
SENIOR SECURED CREDIT FACILITY | 71,600 |  |  | 291,000 |
SENIOR UNSECURED NOTES, net of debt issuance costs, discount and premium | 3,035,915 |  |  | 3,436,860 |
DEFERRED TAX LIABILITIES | 16,764 |  |  | 16,575 |
OTHER LONG-TERM LIABILITIES | 374,950 |  |  | 389,161 |
LONG-TERM LIABILITIES - held for discontinued operations | — |  |  | 529,558 |
Total liabilities | 4,121,134 |  |  | 5,521,909 |
MEZZANINE CAPITAL: |  |  |
Class A Convertible Preferred Units, 15,695,722 and 23,111,918 issued and outstanding at June 30, 2025 and December 31, 2024, respectively | 552,523 |  |  | 813,589 |
PARTNERS’ CAPITAL (DEFICIT): |  |  |
Common unitholders, 122,464,318 units issued and outstanding at June 30, 2025 and December 31, 2024 | (273,274) |  |  | 279,891 |
Accumulated other comprehensive income | — |  |  | 9,486 |
Noncontrolling interests | 438,155 |  |  | 412,817 |
Total partners’ capital | 164,881 |  |  | 702,194 |
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL | $ | 4,838,538 |  |  | $ | 7,037,692 |

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.
3

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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
REVENUES: |  |  |  |  |  |  |
Offshore pipeline transportation | $ | 125,370 |  |  | $ | 99,024 |  |  | $ | 234,257 |  |  | $ | 201,014 |
Marine transportation | 79,617 |  |  | 81,871 |  |  | 160,261 |  |  | 165,445 |
Onshore transportation and services | 172,361 |  |  | 249,284 |  |  | 381,141 |  |  | 498,167 |
Total revenues | 377,348 |  |  | 430,179 |  |  | 775,659 |  |  | 864,626 |
COSTS AND EXPENSES: |  |  |  |  |  |  |
Offshore pipeline transportation operating costs | 35,979 |  |  | 29,892 |  |  | 68,915 |  |  | 57,710 |
Marine transportation operating costs | 49,977 |  |  | 50,602 |  |  | 100,866 |  |  | 103,010 |
Onshore transportation and services product costs | 92,479 |  |  | 159,155 |  |  | 220,170 |  |  | 319,543 |
Onshore transportation and services operating costs | 60,549 |  |  | 71,285 |  |  | 128,558 |  |  | 142,972 |
General and administrative | 14,744 |  |  | 18,299 |  |  | 55,386 |  |  | 32,999 |
Depreciation and amortization | 55,905 |  |  | 51,167 |  |  | 112,076 |  |  | 100,558 |
Total costs and expenses | 309,633 |  |  | 380,400 |  |  | 685,971 |  |  | 756,792 |
OPERATING INCOME | 67,715 |  |  | 49,779 |  |  | 89,688 |  |  | 107,834 |
Equity in earnings of equity investees | 12,330 |  |  | 12,213 |  |  | 24,822 |  |  | 28,654 |
Interest expense, net | (60,754) |  |  | (64,539) |  |  | (130,792) |  |  | (126,873) |
Other expense | (8,935) |  |  | (1,429) |  |  | (9,779) |  |  | (1,429) |
Income (loss) from continuing operations before income taxes | 10,356 |  |  | (3,976) |  |  | (26,061) |  |  | 8,186 |
Income tax benefit (expense) | (345) |  |  | 11 |  |  | (489) |  |  | (798) |
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | 10,011 |  |  | (3,965) |  |  | (26,550) |  |  | 7,388 |
DISCONTINUED OPERATIONS (Note 4): |  |  |  |  |  |  |
Income from discontinued operations, net of tax | — |  |  | 2,578 |  |  | 8,448 |  |  | 10,181 |
Loss from disposal of discontinued operations | — |  |  | — |  |  | (432,193) |  |  | — |
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX | — |  |  | 2,578 |  |  | (423,745) |  |  | 10,181 |
NET INCOME (LOSS) | 10,011 |  |  | (1,387) |  |  | (450,295) |  |  | 17,569 |
Net income attributable to noncontrolling interests | (10,417) |  |  | (7,357) |  |  | (19,186) |  |  | (14,960) |
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. | $ | (406) |  |  | $ | (8,744) |  |  | $ | (469,481) |  |  | $ | 2,609 |
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units | (14,868) |  |  | (21,894) |  |  | (43,270) |  |  | (43,788) |
NET LOSS ATTRIBUTABLE TO COMMON UNITHOLDERS | $ | (15,274) |  |  | $ | (30,638) |  |  | $ | (512,751) |  |  | $ | (41,179) |
Net loss from continuing operations per common unit - Basic and Diluted (Note 12) | $ | (0.12) |  |  | $ | (0.27) |  |  | $ | (0.73) |  |  | $ | (0.42) |
Net loss per common unit - Basic and Diluted (Note 12) | $ | (0.12) |  |  | $ | (0.25) |  |  | $ | (4.19) |  |  | $ | (0.34) |
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS: |  |  |  |  |  |  |
Basic and Diluted | 122,464 |  |  | 122,464 |  |  | 122,464 |  |  | 122,464 |

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.
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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income (loss) | $ | 10,011 |  |  | $ | (1,387) |  |  | $ | (450,295) |  |  | $ | 17,569 |
Other comprehensive income: |  |  |  |  |  |  |
Decrease in benefit plan liability held for discontinued operations | — |  |  | 80 |  |  | 69 |  |  | 160 |
Total Comprehensive income (loss) | 10,011 |  |  | (1,307) |  |  | (450,226) |  |  | 17,729 |
Comprehensive income attributable to noncontrolling interests | (10,417) |  |  | (7,357) |  |  | (19,186) |  |  | (14,960) |
Comprehensive income (loss) attributable to Genesis Energy, L.P. | $ | (406) |  |  | $ | (8,664) |  |  | $ | (469,412) |  |  | $ | 2,769 |

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 (DEFICIT)
(In thousands)

| Number of Common Units |  | Partners’ Capital (Deficit) |  | Noncontrolling Interests |  | Accumulated Other Comprehensive Income |  | Total
Partners’ capital (deficit), March 31, 2025 | 122,464 |  |  | $ | (237,793) |  |  | $ | 425,402 |  |  | $ | — |  |  | $ | 187,609 |
Net income (loss) | — |  |  | (406) |  |  | 10,417 |  |  | — |  |  | 10,011 |
Cash distributions to partners | — |  |  | (20,207) |  |  | — |  |  | — |  |  | (20,207) |
Cash distributions to noncontrolling interests | — |  |  | — |  |  | (13,086) |  |  | — |  |  | (13,086) |
Contributions from noncontrolling interests | — |  |  | — |  |  | 15,422 |  |  | — |  |  | 15,422 |
Distributions to Class A Convertible Preferred unitholders | — |  |  | (14,868) |  |  | — |  |  | — |  |  | (14,868) |
Partners’ capital (deficit), June 30, 2025 | $ | 122,464 |  |  | $ | (273,274) |  |  | $ | 438,155 |  |  | $ | — |  |  | $ | 164,881 |
| Number of Common Units |  | Partners’ Capital |  | Noncontrolling Interests |  | Accumulated Other Comprehensive Income |  | Total
Partners’ capital, March 31, 2024 | 122,464 |  |  | $ | 490,787 |  |  | $ | 375,946 |  |  | $ | 8,120 |  |  | $ | 874,853 |
Net income (loss) | — |  |  | (8,744) |  |  | 7,357 |  |  | — |  |  | (1,387) |
Cash distributions to partners | — |  |  | (18,370) |  |  | — |  |  | — |  |  | (18,370) |
Cash distributions to noncontrolling interests | — |  |  | — |  |  | (9,090) |  |  | — |  |  | (9,090) |
Cash contributions from noncontrolling interests | — |  |  | — |  |  | 7,200 |  |  | — |  |  | 7,200 |
Non-cash contribution to noncontrolling interests | — |  |  | (12,967) |  |  | 12,967 |  |  | — |  |  | — |
Other comprehensive income | — |  |  | — |  |  | — |  |  | 80 |  |  | 80 |
Distributions to Class A Convertible Preferred unitholders | — |  |  | (21,894) |  |  | — |  |  | — |  |  | (21,894) |
Partners’ capital, June 30, 2024 | 122,464 |  |  | $ | 428,812 |  |  | $ | 394,380 |  |  | $ | 8,200 |  |  | $ | 831,392 |

| Number of Common Units |  | Partners’ Capital (Deficit) |  | Noncontrolling Interests |  | Accumulated Other Comprehensive Income |  | Total
Partners’ capital, December 31, 2024 | 122,464 |  |  | $ | 279,891 |  |  | $ | 412,817 |  |  | $ | 9,486 |  |  | $ | 702,194 |
Net income (loss) | — |  |  | (469,481) |  |  | 19,186 |  |  | — |  |  | (450,295) |
Cash distributions to partners | — |  |  | (40,414) |  |  | — |  |  | — |  |  | (40,414) |
Cash distributions to noncontrolling interests | — |  |  | — |  |  | (24,237) |  |  | — |  |  | (24,237) |
Cash contributions from noncontrolling interests | — |  |  | — |  |  | 30,389 |  |  | — |  |  | 30,389 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | 69 |  |  | 69 |
Disposal of benefit plan held for discontinued operations | — |  |  | — |  |  | — |  |  | (9,555) |  |  | (9,555) |
Distributions and returns attributable to Class A Convertible Preferred unitholders | — |  |  | (43,270) |  |  | — |  |  | — |  |  | (43,270) |
Partners’ capital (deficit), June 30 2025 | $ | 122,464 |  |  | $ | (273,274) |  |  | $ | 438,155 |  |  | $ | — |  |  | $ | 164,881 |
| Number of Common Units |  | Partners’ Capital |  | Noncontrolling Interests |  | Accumulated Other Comprehensive Income |  | Total
Partners’ capital, December 31, 2023 | 122,464 |  |  | $ | 519,698 |  |  | $ | 369,450 |  |  | $ | 8,040 |  |  | $ | 897,188 |
Net income | — |  |  | 2,609 |  |  | 14,960 |  |  | — |  |  | 17,569 |
Cash distributions to partners | — |  |  | (36,740) |  |  | — |  |  | — |  |  | (36,740) |
Cash distributions to noncontrolling interests | — |  |  | — |  |  | (19,197) |  |  | — |  |  | (19,197) |
Cash contributions from noncontrolling interests | — |  |  | — |  |  | 16,200 |  |  | — |  |  | 16,200 |
Non-cash contribution to noncontrolling interests | — |  |  | (12,967) |  |  | 12,967 |  |  | — |  |  | — |
Other comprehensive income | — |  |  | — |  |  | — |  |  | 160 |  |  | 160 |
Distributions to Class A Convertible Preferred unitholders | — |  |  | (43,788) |  |  | — |  |  | — |  |  | (43,788) |
Partners’ capital, June 30, 2024 | 122,464 |  |  | $ | 428,812 |  |  | $ | 394,380 |  |  | $ | 8,200 |  |  | $ | 831,392 |

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.
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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

| Six Months Ended June 30,
| 2025 |  | 2024
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |
Net income (loss) | $ | (450,295) |  |  | $ | 17,569 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities - |  |  |
Depreciation, depletion and amortization | 130,938 |  |  | 151,384 |
Amortization and write-off of debt issuance costs, premium and discount | 7,406 |  |  | 7,370 |
Loss from disposal of discontinued operations (Note 4) | 432,193 |  |  | — |
Equity in earnings of investments in equity investees | (24,822) |  |  | (28,654) |
Cash distributions of earnings of equity investees | 24,560 |  |  | 28,654 |
Non-cash effect of long-term incentive compensation plans | 5,638 |  |  | 9,786 |
Deferred and other tax liabilities | (68) |  |  | (13) |
Unrealized gains on derivative transactions | (238) |  |  | (10,941) |
Other, net | 16,539 |  |  | 6,255 |
Net changes in components of operating assets and liabilities (Note 15) | (70,059) |  |  | 49,232 |
Net cash provided by operating activities | 71,792 |  |  | 230,642 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |
Payments to acquire fixed and intangible assets | (136,142) |  |  | (346,443) |
Proceeds from disposal of discontinued operations, net of cash divested (Note 4) | 996,642 |  |  | — |
Cash distributions received from equity investees - return of investment | 11,949 |  |  | 11,687 |
Investments in equity investees | — |  |  | (285) |
Proceeds from asset sales | 692 |  |  | 10,996 |
Net cash provided by (used in) investing activities | 873,141 |  |  | (324,045) |
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |
Borrowings on senior secured credit facility | 494,900 |  |  | 766,600 |
Repayments on senior secured credit facility | (714,300) |  |  | (930,100) |
Proceeds from issuance of senior unsecured notes (Note 10) | — |  |  | 700,000 |
Repayment of senior unsecured notes (Note 10) | (414,370) |  |  | (339,310) |
Repayment of Alkali senior secured notes | — |  |  | (5,815) |
Debt issuance costs | (1,482) |  |  | (13,252) |
Contributions from noncontrolling interests | 30,389 |  |  | 16,200 |
Distributions to noncontrolling interests | (24,237) |  |  | (19,197) |
Distributions to common unitholders | (40,414) |  |  | (36,740) |
Distributions to Class A Convertible Preferred unitholders | (41,836) |  |  | (43,788) |
Redemption of Class A Convertible Preferred Units (Note 11) | (262,500) |  |  | — |
Other, net | 3,817 |  |  | 3,266 |
Net cash provided by (used in) financing activities | (970,033) |  |  | 97,864 |
Net increase (decrease) in cash, cash equivalents and restricted cash | (25,100) |  |  | 4,461 |
Cash, cash equivalents and restricted cash at beginning of period | 29,552 |  |  | 28,038 |
Cash, cash equivalents, and restricted cash at beginning of period: discontinued operations | 22,200 |  |  | 21,806 |
Cash and cash equivalents at beginning of period: continuing operations | 7,352 |  |  | 6,232 |
Cash, cash equivalents and restricted cash at end of period | 4,452 |  |  | 32,499 |
Cash, cash equivalents and restricted cash at end of period: discontinued operations | — |  |  | 28,065 |
Cash and cash equivalents at end of period: continuing operations | $ | 4,452 |  |  | $ | 4,434 |

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 master limited partnership founded in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry. Our operations are primarily located in the Gulf of America and in the Gulf Coast region of the United States. We provide an integrated suite of services to crude oil and natural gas producers, refiners and industrial and commercial enterprises. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.
In the first quarter of 2025, we re-organized our operating segments as a result of the way our chief operating decision maker, who is our Chief Executive Officer (our “CODM”), evaluates the performance of operations, develops strategy and allocates resources, including capital. Our sulfur services business, formerly reported under our Soda and Sulfur Services reporting segment with our Alkali Business (as defined below), is now reported under our onshore transportation and services reporting segment along with our previously reported onshore facilities and transportation segment. As a result of this change, we now manage our businesses through the following three 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 America;
•Marine transportation, which provides waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America; and
•Onshore transportation and services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products, as well as the processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly pronounced “nash”).
Basis of Presentation and Consolidation
The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries.
On February 28, 2025, we completed the sale of our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (the “Alkali Business”) for a gross purchase price of approximately $1.425 billion. The Company determined that the exit of the Alkali Business and its operations in Wyoming represented a strategic and geographic shift that met the criteria for discontinued operations (see Note 4 for further discussion). Accordingly, the Company has separately reported the operations from the Alkali Business in the Unaudited Condensed Consolidated Statements of Operations and the related assets and liabilities of the Alkali Business in the Unaudited Condensed Consolidated Balance Sheets as discontinued operations. These changes have been applied retrospectively to all periods presented. The disclosures included within the accompanying notes to the Unaudited Condensed Consolidated Financial Statements are representative of the Company’s continuing operations.
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, 2024 (our “Annual Report”).
Except for 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.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2. Recent Accounting Developments
We have adopted guidance under ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”), which enhanced the disclosures required for operating segments. We have applied the disclosures required under ASU 2023-07 retrospectively to all periods presented. Refer to Note 13 for details.
In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” (“ASU 2023-09”), which is intended to enhance the transparency and usefulness of income tax disclosures. The amendments in ASU 2023-09 provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid information. ASU 2023-09 is effective prospectively to all annual periods beginning after December 15, 2024. We are currently evaluating the impact of this standard on our disclosures.
In November 2024, the FASB issued ASU 2024-03, “Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures” (“ASU 2024-03”), which requires additional disclosures of the specific types of expenses included in the expense captions presented on the face of the income statement. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual reporting periods beginning after December 15, 2027. The requirements will be applied prospectively, with the option for retrospective application. Early adoption is permitted. We are currently evaluating the impact of this standard on our disclosures.
All other new accounting pronouncements that have been issued, but not yet effective are currently being evaluated and at this time are not expected to have a material impact on our financial position or results of operations.
3. Revenue Recognition
Revenue from Contracts with Customers
The following tables reflect the disaggregation of our revenues by major category for the three months ended June 30, 2025 and 2024, respectively:

| Three Months Ended June 30, 2025
| Offshore pipeline transportation |  | Marine transportation |  | Onshore transportation and services |  | Consolidated
Fee-based revenues | $ | 125,370 |  |  | $ | 79,617 |  |  | $ | 16,713 |  |  | $ | 221,700 |
Product sales | — |  |  | — |  |  | 137,885 |  |  | 137,885 |
Sulfur services | — |  |  | — |  |  | 17,763 |  |  | 17,763 |
Total revenues | $ | 125,370 |  |  | $ | 79,617 |  |  | $ | 172,361 |  |  | $ | 377,348 |

| Three Months Ended June 30, 2024
| Offshore pipeline transportation |  | Marine transportation |  | Onshore transportation and services |  | Consolidated
Fee-based revenues | $ | 99,024 |  |  | $ | 81,871 |  |  | $ | 16,199 |  |  | $ | 197,094 |
Product sales | — |  |  | — |  |  | 212,659 |  |  | 212,659 |
Sulfur services | — |  |  | — |  |  | 20,426 |  |  | 20,426 |
Total revenues | $ | 99,024 |  |  | $ | 81,871 |  |  | $ | 249,284 |  |  | $ | 430,179 |

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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following tables reflect the disaggregation of our revenues by major category for the six months ended June 30, 2025 and 2024, respectively:

| Six Months Ended June 30, 2025
| Offshore pipeline transportation |  | Marine transportation |  | Onshore transportation and services |  | Consolidated
Fee-based revenues | $ | 234,257 |  |  | $ | 160,261 |  |  | $ | 30,218 |  |  | $ | 424,736 |
Product sales | — |  |  | — |  |  | 312,148 |  |  | 312,148 |
Sulfur services | — |  |  | — |  |  | 38,775 |  |  | 38,775 |
Total revenues | $ | 234,257 |  |  | $ | 160,261 |  |  | $ | 381,141 |  |  | $ | 775,659 |

| Six Months Ended June 30, 2024
| Offshore pipeline transportation |  | Marine transportation |  | Onshore transportation and services |  | Consolidated
Fee-based revenues | $ | 201,014 |  |  | $ | 165,445 |  |  | $ | 29,486 |  |  | $ | 395,945 |
Product sales | — |  |  | — |  |  | 425,368 |  |  | 425,368 |
Sulfur services | — |  |  | — |  |  | 43,313 |  |  | 43,313 |
Total revenues | $ | 201,014 |  |  | $ | 165,445 |  |  | $ | 498,167 |  |  | $ | 864,626 |

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.
Contract Assets and Liabilities
The table below depicts our contract asset and liability balances at June 30, 2025 and December 31, 2024:

|  |  |  | Contract Assets |  | Contract Liabilities
|  |  |  | Other Assets |  | Accrued Liabilities |  | Other Long-Term Liabilities
Balance at December 31, 2024 |  |  |  | $ | 5,174 |  |  | $ | 41,618 |  |  | $ | 82,164 |
Balance at June 30, 2025 |  |  |  | 6,498 |  |  | 33,400 |  |  | 73,350 |

For the six months ended June 30, 2025 and 2024, we recognized revenue of $21.4 million and $6.8 million, respectively, that was included in contract liabilities at the beginning of the period.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Transaction Price Allocations to Remaining Performance Obligations
We are required to disclose the aggregate amount of our transaction prices that are allocated to unsatisfied performance obligations as of June 30, 2025. 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. In our onshore transportation and services segment, we have certain contractual arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines and related assets.
The following chart depicts how we expect to recognize revenues for future periods related to these contracts:

| Offshore Pipeline Transportation |  |  | Onshore Transportation and Services
Remainder of 2025 | $ | 125,255 |  |  |  | $ | 14,947 |
2026 | 208,315 |  |  |  | 29,931 |
2027 | 139,076 |  |  |  | 14,763 |
2028 | 61,272 |  |  |  | 10,000 |
2029 | 30,400 |  |  |  | 2,500 |
Thereafter | 83,888 |  |  |  | — |
Total | $ | 648,206 |  |  |  | $ | 72,141 |

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4. Discontinued Operations
On February 28, 2025, we completed the sale of the Alkali Business to an indirect affiliate of WE Soda Ltd for a gross purchase price of $1.425 billion. The sale generated proceeds of approximately $1.0 billion, which reflects the net proceeds after the payment of transaction costs and expenses, the assumption of $413.4 million of our then outstanding 5.875% senior secured notes due 2042 (the “Alkali senior secured notes”) by an indirect affiliate of WE Soda Ltd, and cash divested.
A reconciliation of the line items constituting pretax income from discontinued operations to net income (loss) from discontinued operations, net of tax is as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Major classes of line items constituting income (loss) from discontinued operations: |  |  |  |  |  |  |
Revenues | $ | — |  |  | $ | 326,082 |  |  | $ | 200,532 |  |  | $ | 661,740 |
Operating costs | — |  |  | (290,447) |  |  | (168,871) |  |  | (587,413) |
General and administrative | — |  |  | (247) |  |  | (156) |  |  | (556) |
Depreciation, depletion and amortization | — |  |  | (26,446) |  |  | (18,862) |  |  | (50,826) |
Interest expense, net | — |  |  | (6,331) |  |  | (4,179) |  |  | (12,731) |
Pretax income from discontinued operations | — |  |  | 2,611 |  |  | 8,464 |  |  | 10,214 |
Loss from the sale of the Alkali Business | — |  |  | — |  |  | (432,193) |  |  | — |
Total pretax income (loss) from discontinued operations | — |  |  | 2,611 |  |  | (423,729) |  |  | 10,214 |
Income tax expense | — |  |  | (33) |  |  | (16) |  |  | (33) |
Net income (loss) from discontinued operations, net of tax | $ | — |  |  | $ | 2,578 |  |  | $ | (423,745) |  |  | $ | 10,181 |

A summary of our cash flows associated with our discontinued operations is as follows:

|  |  | Six Months Ended June 30,
|  |  |  |  | 2025 |  | 2024
Net cash flows provided by operating activities |  |  |  |  | $ | 31,453 |  |  | $ | 136,985 |
Net cash flows used in investing activities |  |  |  |  | (11,666) |  |  | (124,911) |
Net cash flows used in financing activities |  |  |  |  | — |  |  | (5,815) |

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). Certain of our leases contain options to extend the life of the lease at our sole discretion and we considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of 12 months or 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, office space and equipment, and facilities and equipment leases. Additionally, it includes our unamortized prepaid rents and our deferred rents. Current and non-current lease liabilities are recorded within “Accrued liabilities” and “Other long-term liabilities,” respectively, on our Unaudited Condensed Consolidated Balance Sheets.
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Lessor Arrangements
We have certain contracts discussed below in which we act as a lessor. We may also, from time to time, sublease certain of our transportation and facilities equipment to third parties.
Operating Leases
During the three and six months months ended June 30, 2025 and 2024, we acted as a lessor in a revenue contract associated with our 330,000 barrel-capacity ocean going tanker, the M/T American Phoenix, included in our marine transportation segment. Our lease revenues for this arrangement were $7.4 million and $7.1 million for the three months ended June 30, 2025 and 2024, respectively, and $14.6 million and $13.9 million for the six months ended June 30, 2025 and 2024, respectively.
The M/T American Phoenix is under contract through mid-2027. For the remainder of 2025, 2026, and through the expiration of the contract in 2027, we expect to receive undiscounted cash flows from lease payments of $14.9 million, $30.6 million, and $15.2 million, respectively. Our agreements generally contain clauses that may limit the use of the asset or require certain actions be taken by the lessee to maintain the asset for future performance.
6. Inventories
The major components of inventories were as follows:

| June 30, 2025 |  | December 31, 2024
Crude oil | $ | 41,567 |  |  | $ | 20,381 |
NaHS | 8,499 |  |  | 10,902 |
Caustic soda | 8,118 |  |  | 6,499 |
Total | $ | 58,184 |  |  | $ | 37,782 |

Inventories are valued at the lower of cost or net realizable value. As of June 30, 2025 and December 31, 2024, the net realizable value of inventories was below cost by $0.2 million and $0.4 million, respectively, which triggered a reduction of the value of inventory in our Unaudited Condensed Consolidated Financial Statements by this amount.
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7. Fixed Assets and Asset Retirement Obligations
Fixed Assets
Fixed assets consisted of the following:

| June 30, 2025 |  | December 31, 2024
Crude oil and natural gas pipelines and related assets | $ | 3,507,121 |  |  | $ | 3,367,908 |
Onshore facilities, machinery and equipment | 290,655 |  |  | 293,436 |
Transportation equipment | 24,273 |  |  | 22,976 |
Marine vessels | 1,067,572 |  |  | 1,062,720 |
Land, buildings and improvements | 88,545 |  |  | 88,545 |
Office equipment, furniture and fixtures | 10,337 |  |  | 10,101 |
Construction in progress(1) | 327,226 |  |  | 408,509 |
Other | 26,665 |  |  | 26,665 |
Fixed assets, at cost | 5,342,394 |  |  | 5,280,860 |
Less: Accumulated depreciation | (1,816,766) |  |  | (1,740,974) |
Net fixed assets | $ | 3,525,628 |  |  | $ | 3,539,886 |

(1)Construction in progress primarily relates to our ongoing offshore growth capital projects, which are expected to be completed in 2025, and represents 100% of the costs incurred, including those funded by our noncontrolling interest holder.
Our depreciation expense for the periods presented was as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Depreciation expense | $ | 53,347 |  |  | $ | 48,715 |  |  | $ | 106,947 |  |  | $ | 95,647 |

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, 2024:

ARO liability balance, December 31, 2024 | $ | 254,054 |
Accretion expense | 5,946 |
Settlements | (1,321) |
ARO liability balance, June 30, 2025 | $ | 258,679 |

At June 30, 2025 and December 31, 2024, $25.8 million is included as current in “Accrued liabilities” on our Unaudited Condensed Consolidated Balance Sheets. The remainder of the ARO liability as of June 30, 2025 and December 31, 2024 is included in “Other long-term liabilities” on our Unaudited Condensed Consolidated Balance Sheets.
Certain of our unconsolidated affiliates have AROs recorded at June 30, 2025 and December 31, 2024 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. 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 the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At June 30, 2025 and December 31, 2024, the unamortized excess cost amounts totaled $270.0 million and $277.1 million, respectively. We amortize the differences in carrying value as changes in equity earnings.
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The following table presents information included in our Unaudited Condensed Consolidated Financial Statements related to our equity investees:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Genesis’ share of operating earnings | $ | 15,896 |  |  | $ | 15,779 |  |  | $ | 31,954 |  |  | $ | 35,786 |
Amortization of differences attributable to Genesis’ carrying value of equity investments | (3,566) |  |  | (3,566) |  |  | (7,132) |  |  | (7,132) |
Equity in earnings of equity investees | $ | 12,330 |  |  | $ | 12,213 |  |  | $ | 24,822 |  |  | $ | 28,654 |
Distributions received(1) | $ | 17,925 |  |  | $ | 17,092 |  |  | $ | 36,509 |  |  | $ | 40,341 |

(1) Distributions attributab le to the respective period and received within 15 days subsequent to the respective period end.
Poseidon’s Revolving Credit Facility
Poseidon Oil Pipeline Company, LLC (“Poseidon”) has a revolving credit facility, which was amended and restated on May 9, 2025 (the “May 2025 credit facility”). Borrowings under Poseidon’s revolving credit facility have historically been used to fund spending on capital projects. The May 2025 credit facility, which matures on May 9, 2029, is non-recourse to Poseidon’s owners and secured by its assets. T he May 2025 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:

| June 30, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Carrying Value |  | Gross Carrying Amount |  | Accumulated Amortization |  | Carrying Value
Offshore pipeline contract intangibles | $ | 158,101 |  |  | $ | 82,518 |  |  | $ | 75,583 |  |  | $ | 158,101 |  |  | $ | 78,357 |  |  | $ | 79,744 |
Other | 22,864 |  |  | 17,998 |  |  | 4,866 |  |  | 22,633 |  |  | 17,090 |  |  | 5,543 |
Total | $ | 180,965 |  |  | $ | 100,516 |  |  | $ | 80,449 |  |  | $ | 180,734 |  |  | $ | 95,447 |  |  | $ | 85,287 |

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Amortization of intangible assets | $ | 2,558 |  |  | $ | 2,452 |  |  | $ | 5,129 |  |  | $ | 4,911 |

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

Remainder of | 2025 | $ | 5,153 |
| 2026 | 9,911 |
| 2027 | 9,336 |
| 2028 | 8,652 |
| 2029 | 8,592 |

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10. Debt
Our obligations under debt arrangements consisted of the following:

| June 30, 2025 |  | December 31, 2024
| Principal |  | Unamortized Discount and Debt Issuance Costs |  | Net Value |  | Principal |  | Unamortized Premium, Discount and Debt Issuance Costs |  | Net Value
Senior secured credit facility(1) | $ | 71,600 |  |  | $ | — |  |  | $ | 71,600 |  |  | $ | 291,000 |  |  | $ | — |  |  | $ | 291,000 |
8.000% senior unsecured notes due 2027 | — |  |  | — |  |  | — |  |  | 406,245 |  |  | 933 |  |  | 405,312 |
7.750% senior unsecured notes due 2028 | 679,360 |  |  | 3,873 |  |  | 675,487 |  |  | 679,360 |  |  | 4,622 |  |  | 674,738 |
8.250% senior unsecured notes due 2029 | 600,000 |  |  | 12,353 |  |  | 587,647 |  |  | 600,000 |  |  | 13,993 |  |  | 586,007 |
8.875% senior unsecured notes due 2030 | 500,000 |  |  | 6,353 |  |  | 493,647 |  |  | 500,000 |  |  | 7,015 |  |  | 492,985 |
7.875% senior unsecured notes due 2032 | 700,000 |  |  | 10,698 |  |  | 689,302 |  |  | 700,000 |  |  | 11,476 |  |  | 688,524 |
8.000% senior unsecured notes due 2033 | 600,000 |  |  | 10,168 |  |  | 589,832 |  |  | 600,000 |  |  | 10,706 |  |  | 589,294 |
Total long-term debt | $ | 3,150,960 |  |  | $ | 43,445 |  |  | $ | 3,107,515 |  |  | $ | 3,776,605 |  |  | $ | 48,745 |  |  | $ | 3,727,860 |

(1)Unamortized debt issuance costs associated with our senior secured credit facility (included in “Other Assets” on the Unaudited Condensed Consolidated Balance Sheets), were $6.4 million and $7.9 million as of June 30, 2025 and December 31, 2024, respectively.
Senior Secured Credit Facility
On July 19, 2024, we entered into the Seventh Amended and Restated Credit Agreement (our “credit agreement”) to replace our Sixth Amended and Restated Credit Agreement. The credit agreement provides for a $900 million senior secured revolving credit facility and matures on September 1, 2028, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, provided that if more than $150 million of our 7.750% senior unsecured notes due February 1, 2028 (the “2028 Notes”) remain outstanding as of November 2, 2027, the credit agreement matures on such date.
On December 11, 2024, we entered into the First Amendment to the credit agreement which resulted in several changes to certain terms and covenants including: (i) an increase of the maximum Consolidated Leverage Ratio covenant (our “leverage ratio”) from 5.50 to 1.00 to 5.75 to 1.00 for the fiscal quarters ending December 31, 2024 through September 30, 2025, returning to 5.50 to 1.00 thereafter and (ii) changes to the minimum Consolidated Interest Coverage Ratio covenant from 2.40 to 1.00 to (A) 2.00 to 1.00 for the fiscal quarters ending December 31, 2024 through December 31, 2025, (B) 2.25 to 1.00 for the fiscal quarters ending March 31, 2026 through December 31, 2026, and (C) 2.50 to 1.00 for the remainder of the term.
On February 27, 2025, in connection with the sale of our Alkali Business, we entered into the Second Amendment to the credit agreement. This amendment provides for: (i) a reduction from $900 million to $800 million of total borrowing capacity under our senior secured credit facility; (ii) unlimited cash netting against our outstanding debt for purposes of our leverage ratio calculation if our credit facility is undrawn at the end of a reporting period, otherwise a maximum netting of $25 million is allowed; and (iii) an increased permitted investment basket under certain circumstances that will allow us to opportunistically purchase existing private or public securities across our capital structure.
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At June 30, 2025, the key terms for rates under our senior secured credit facility (which are dependent on our leverage ratio as defined in the credit agreement) are as follows:
•The interest rate on borrowings may be based on an alternate base rate or Term Secured Overnight Financing Rate (“SOFR”), at our option. Interest on alternate base rate loans is equal to the sum of (a) the highest of (i) the prime rate in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% and (iii) the Adjusted Term SOFR (as defined in our credit agreement) for a one-month tenor in effect on such day plus 1% and (b) the applicable margin. The Adjusted Term SOFR is equal to the sum of (a) the Term SOFR rate (as defined in our credit agreement) for such period plus (b) the Term SOFR Adjustment of 0.1% plus (c) the applicable margin. The applicable margin varies from 2.25% to 3.50% on Term SOFR borrowings and from 1.25% to 2.50% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At June 30, 2025, the applicable margins on our borrowings were 2.50% for alternate base rate borrowings and 3.50% 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 June 30, 2025, our letter of credit rate was 3.50%.
•We pay a commitment fee on the unused portion of the senior secured credit facility. The commitment fee rates on the unused committed amount range from 0.30% to 0.50% per annum depending on our leverage ratio. At June 30, 2025, 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 $150 million, subject to lender consent and certain other customary conditions.
At June 30, 2025, we had $71.6 million borrowed under our senior secured credit facility. Our inventory financing sublimit as of June 30, 2025 was $36.0 million of the maximum allowed of $200 million. Our credit agreement allows up to $50 million of the capacity to be used for letters of credit, of which $4.5 million was outstanding at June 30, 2025. 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 June 30, 2025 was $723.9 million, subject to compliance with covenants. Our credit agreement does not include a “borrowing base” limitation except with respect to our inventory loans.
Senior Unsecured Notes Transactions
On April 3, 2025, using a portion of the cash proceeds from the sale of the Alkali Business, we redeemed the remaining $406.2 million of principal outstanding on the 8.000% senior unsecured notes due January 15, 2027 (the “2027 Notes”), and paid the related accrued interest and redemption premium on those notes that were redeemed. We incurred a net loss of $8.9 million associated with the redemption premium and the write-off of the related unamortized debt issuance costs and premium on the redeemed 2027 Notes, which is recorded in “Other expense” in our Unaudited Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2025.
On May 9, 2024, we issued $700.0 million in aggregate principal amount of 7.875% senior unsecured notes due May 15, 2032 (the “2032 Notes”). The issuance of our 2032 Notes generated net proceeds of approximately $688 million, net of issuance costs incurred. The net proceeds were used to redeem $339.3 million of our existing 6.25% senior unsecured notes due May 15, 2026 (the “2026 Notes”) and pay the related accrued interest. The remaining proceeds were used to repay a portion of the borrowings outstanding under our senior secured credit facility at the time, and for general partnership purposes. We incurred a loss of $1.4 million associated with the write-off of the related unamortized debt issuance costs on our 2026 Notes, which is recorded in “Other expense” in our Unaudited Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2024.
Our $3.1 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except for certain immaterial subsidiaries. The 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.
11. Partners’ Capital (Deficit), Mezzanine Capital and Distributions
At June 30, 2025, 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
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Class A Common Units under certain circumstances, subject to certain exceptions. At June 30, 2025, we had 15,695,722 Class A Convertible Preferred Units outstanding, which are discussed below in further detail.
In an effort to return capital to our investors, we announced a common equity repurchase program (the “Repurchase Program”) on August 8, 2023. The Repurchase Program authorizes the repurchase from time to time of up to 10% of our then outstanding Class A Common Units, or 12,253,922 units, via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. These repurchases may be made pursuant to a repurchase plan or plans that comply with Rule 10b5-1 under the Securities Exchange Act of 1934. The Repurchase Program 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. The Repurchase Program will be reviewed no later than December 31, 2026 and may be suspended or discontinued at any time prior thereto. During 2024 and 2025, we did not repurchase any Class A Common Units, and to date, we have purchased 114,900 Class A Common Units under the Repurchase Program.
Distributions
We paid, or will pay, the following cash distributions to our common unitholders in 2024 and 2025:

Distribution For |  | Date Paid |  | Per Unit Amount |  | Total Amount |
2024 |  |  |  |  |  |  |
1 st Quarter |  | May 15, 2024 |  | $ | 0.150 |  |  | $ | 18,370 |  |
2 nd Quarter |  | August 14, 2024 |  | $ | 0.150 |  |  | $ | 18,370 |  |
3 rd Quarter |  | November 14, 2024 |  | $ | 0.165 |  |  | $ | 20,207 |  |
4 th Quarter |  | February 14, 2025 |  | $ | 0.165 |  |  | $ | 20,207 |  |
2025 |  |  |  |  |  |  |
1 st Quarter |  | May 15, 2025 |  | $ | 0.165 |  |  | $ | 20,207 |  |
2 nd Quarter(1) |  | August 14, 2025 |  | $ | 0.165 |  |  | $ | 20,207 |  |

(1)This distribution was declared in July 2025 and will be paid to unitholders of record as of July 31, 2025.
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 then redeemable and we did not have plans or expect any events that constitute a change of control in our partnership agreement.
On March 6, 2025, we entered into purchase agreements with certain Class A Convertible Preferred unitholders whereby we purchased a total of 7,416,196 Class A Convertible Preferred Units (the “Purchased Units”) at a purchase price of $35.40 per unit. In addition, we paid a distribution of $5.1 million (or $0.6841 per Purchased Unit), which represented distributions that accrued on the Purchased Units from January 1, 2025 through March 6, 2025.
Net Income (Loss) Attributable to Genesis Energy, L.P. is adjusted for distributions and returns attributable to the Class A Convertible Preferred Units that are paid in the period to arrive at Net Loss attributable to Common Unitholders. Net Income (Loss) Attributable to Genesis Energy, L.P. was reduced by $14.9 million and $41.8 million for the three and six months ending June 30, 2025, respectively, and $21.9 million and $43.8 million for the three and six months ending June 30, 2024, 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 six months ended June 30, 2025, Net Loss Attributable to Genesis Energy L.P. was also reduced by $1.4 million due to returns attributable to the Class A Convertible Preferred Units accumulated in the period.
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As of June 30, 2025, 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 be redeemed. 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 could 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 2024 and 2025:

Distribution For |  | Date Paid |  | Per Unit Amount |  | Total Amount
2024 |  |  |  |  |  |
1 st Quarter |  | May 15, 2024 |  | $ | 0.9473 |  |  | $ | 21,894 |
2 nd Quarter |  | August 14, 2024 |  | $ | 0.9473 |  |  | $ | 21,894 |
3 rd Quarter |  | November 14, 2024 |  | $ | 0.9473 |  |  | $ | 21,894 |
4th Quarter |  | February 14, 2025 |  | $ | 0.9473 |  |  | $ | 21,894 |
2025 |  |  |  |  |  |
1 st Quarter(1) |  | May 15, 2025 |  | $ | 0.9473 |  |  | $ | 19,942 |
2 nd Quarter(2) |  | August 14, 2025 |  | $ | 0.9473 |  |  | $ | 14,868 |

(1)Approximately $5.1 million of this distribution is associated with the Purchased Units and was paid on March 6, 2025.
(2)This distribution was declared in July 2025 and will be paid to unitholders of record as of July 31, 2025.
Noncontrolling Interests
We own a 64% membership interests in Cameron Highway Oil Pipeline Company, LLC (“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 Partners’ Capital (Deficit).
12. Net Income (Loss) Per Common Unit
Basic net income (loss) per common unit is computed by dividing net income (loss) attributable to Genesis Energy, L.P., after considering income attributable to our Class A Convertible 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 six months ended June 30, 2025 and 2024, the effect of the assumed conversion of the 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 illustrates the computation of basis and diluted net income (loss) per common unit:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income (loss) from continuing operations | $ | 10,011 |  |  | $ | (3,965) |  |  | $ | (26,550) |  |  | $ | 7,388 |
Less: Net income attributable to noncontrolling interests | (10,417) |  |  | (7,357) |  |  | (19,186) |  |  | (14,960) |
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units | (14,868) |  |  | (21,894) |  |  | (43,270) |  |  | (43,788) |
Net loss attributable to common unitholders from continuing operations | (15,274) |  |  | (33,216) |  |  | (89,006) |  |  | (51,360) |
Net income (loss) from discontinued operations | — |  |  | 2,578 |  |  | (423,745) |  |  | 10,181 |
Net loss attributable to common unit holders | $ | (15,274) |  |  | $ | (30,638) |  |  | $ | (512,751) |  |  | $ | (41,179) |
Weighted average outstanding units | 122,464 |  |  | 122,464 |  |  | 122,464 |  |  | 122,464 |
Net loss from continuing operations per common unit - Basic and Diluted | $ | (0.12) |  |  | $ | (0.27) |  |  | $ | (0.73) |  |  | $ | (0.42) |
Net income (loss) from discontinued operations per common unit - Basic and Diluted | — |  |  | 0.02 |  |  | (3.46) |  |  | 0.08 |
Net loss per common unit - Basic and Diluted | $ | (0.12) |  |  | $ | (0.25) |  |  | $ | (4.19) |  |  | $ | (0.34) |

13. Business Segment Information
In the first quarter of 2025, we reorganized our operating segments as a result of the way our CODM evaluates the performance of operations, develops strategy and allocates resources, including capital. Our sulfur services business, formerly reported under our soda and sulfur services reporting segment with our previously owned Alkali Business (see Note 4), is now reported under our onshore transportation and services reporting segment. As a result of this change, we now manage our businesses through three divisions that constitute our reportable segments. Our reportable segments are primarily organized around the different products and services we provide to our customers and include the following: (i) offshore pipeline transportation; (ii) marine transportation; and (iii) onshore transportation and services.
Our offshore pipeline transportation segment consists of our offshore transportation of crude oil and natural gas in the Gulf of America, which focuses on providing a suite of services to integrated and large independent energy companies.
Our marine transportation segment provides waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America primarily to customers such as refiners and large energy companies.
Our onshore transportation and services segment provides services through a combination of purchasing, transporting, storing, blending and marketing crude oil and petroleum products primarily to crude oil refiners and producers and performs the processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur and selling the related by-product, NaHS (our sulfur services business).
Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States.
Our CODM evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, and, where relevant, capital investment.
Segment Margin is viewed by our CODM as the primary measure that is most aligned with the measurement principles most consistent with those used in calculating the corresponding amounts in our Unaudited Condensed Consolidated Financial Statements. We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation, amortization and accretion), segment general and administrative expenses, all of which are net of the effects of our noncontrolling interests, plus our equity in distributable cash generated by our equity investees and unrestricted subsidiaries. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation plan.
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Segment information for the periods presented below was as follows:

| Offshore pipeline transportation |  | Marine transportation |  | Onshore transportation and services |  | Total
Three Months Ended June 30, 2025 |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |
External Customers | $ | 125,128 |  |  | $ | 79,617 |  |  | $ | 172,603 |  |  | $ | 377,348 |
Intersegment Revenue(1) | 242 |  |  | — |  |  | (242) |  |  | — |
Total revenues of reportable segments(2) | $ | 125,370 |  |  | $ | 79,617 |  |  | $ | 172,361 |  |  | $ | 377,348 |
Segment Operating Expenses | (35,979) |  |  | (49,977) |  |  | (60,549) |  |  | (146,505) |
Segment Product Costs | — |  |  | — |  |  | (92,479) |  |  | (92,479) |
Other Segment Items(3) | (1,797) |  |  | 177 |  |  | (875) |  |  | (2,495) |
Segment Margin(4) | $ | 87,594 |  |  | $ | 29,817 |  |  | $ | 18,458 |  |  | $ | 135,869 |
Three Months Ended June 30, 2024 |  |  |  |  |  |  |
Total revenues of reportable segments(2)(5) | $ | 99,024 |  |  | $ | 81,871 |  |  | $ | 249,284 |  |  | $ | 430,179 |
Segment Operating Expenses | (29,892) |  |  | (50,602) |  |  | (71,285) |  |  | (151,779) |
Segment Product Costs | — |  |  | — |  |  | (159,155) |  |  | (159,155) |
Other Segment Items(3) | 16,999 |  |  | 274 |  |  | 1,398 |  |  | 18,671 |
Segment Margin(4) | $ | 86,131 |  |  | $ | 31,543 |  |  | $ | 20,242 |  |  | $ | 137,916 |
Six Months Ended June 30, 2025 |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |
External Customers | $ | 234,015 |  |  | $ | 160,261 |  |  | $ | 381,383 |  |  | $ | 775,659 |
Intersegment Revenue(1) | 242 |  |  | — |  |  | (242) |  |  | — |
Total revenues of reportable segments(2) | $ | 234,257 |  |  | $ | 160,261 |  |  | $ | 381,141 |  |  | $ | 775,659 |
Segment Operating Expenses | (68,915) |  |  | (100,866) |  |  | (128,558) |  |  | (298,339) |
Segment Product Costs | — |  |  | — |  |  | (220,170) |  |  | (220,170) |
Other Segment Items(3) | (1,200) |  |  | 443 |  |  | 871 |  |  | 114 |
Segment Margin(4) | $ | 164,142 |  |  | $ | 59,838 |  |  | $ | 33,284 |  |  | $ | 257,264 |
Six Months Ended June 30, 2024 |  |  |  |  |  |  |
Total revenues of reportable segments(2)(5) | $ | 201,014 |  |  | $ | 165,445 |  |  | $ | 498,167 |  |  | $ | 864,626 |
Segment Operating Expenses | (57,710) |  |  | (103,010) |  |  | (142,972) |  |  | (303,692) |
Segment Product Costs | — |  |  | — |  |  | (319,543) |  |  | (319,543) |
Other Segment Items(3) | 40,633 |  |  | 471 |  |  | 2,688 |  |  | 43,792 |
Segment Margin(4) | $ | 183,937 |  |  | $ | 62,906 |  |  | $ | 38,340 |  |  | $ | 285,183 |

(1)Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
(2)Total revenues of reportable segments in the table above agrees to “Total revenues” as seen in our Unaudited Condensed Consolidated Statements of Operations for each respective period.
(3)Other Segment Items primarily includes adjustments related to the difference in timing of cash receipts for certain contractual agreements (applicable to our offshore pipeline transportation and onshore transportation and services segments), segment general and administrative expenses less the non-cash effects of our LTIP plan (applicable to all reportable segments), net effects of our noncontrolling interests (applicable to our offshore pipeline transportation segment), adjustments to include distributable cash generated by our equity investees (applicable to our offshore pipeline transportation and onshore transportation and services segments), and unrealized gains and losses from the valuation of our commodity derivative transactions (excluding fair value hedges) (applicable to our onshore transportation and services segment).
(4)A reconciliation of Income (loss) from continuing operations before income taxes to total Segment Margin for the periods is presented below.
(5)There were no intersegment revenues for the three and six months ended June 30, 2024.
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Total assets by reportable segment were as follows:

| June 30, 2025 |  | December 31, 2024
Offshore pipeline transportation | $ | 2,769,350 |  |  | $ | 2,748,296 |
Marine transportation | 629,719 |  |  | 641,082 |
Onshore transportation and services | 1,398,152 |  |  | 1,401,238 |
Total reportable segment assets | $ | 4,797,221 |  |  | $ | 4,790,616 |
Other assets | 41,317 |  |  | 39,656 |
Assets held for discontinued operations | — |  |  | 2,207,420 |
Total consolidated assets | $ | 4,838,538 |  |  | $ | 7,037,692 |

Total growth and maintenance capital expenditures for fixed and intangible assets (including enhancements to existing facilities and construction of growth projects as well as contributions to equity investees) by reportable segment for the six months ended June 30, 2025 and 2024 were as follows:

|  |  | Six Months Ended June 30,
|  |  |  |  | 2025 |  | 2024
Offshore pipeline transportation(1) |  |  |  |  | $ | 59,136 |  |  | $ | 119,414 |
Marine transportation |  |  |  |  | 29,452 |  |  | 41,842 |
Onshore transportation and services |  |  |  |  | 4,575 |  |  | 13,816 |
Total reportable segment capital expenditures |  |  |  |  | $ | 93,163 |  |  | $ | 175,072 |
Other |  |  |  |  | 654 |  |  | 6,088 |
Total consolidated capital expenditures(2) |  |  |  |  | $ | 93,817 |  |  | $ | 181,160 |

(1)Capital expenditures in our offshore pipeline transportation segment for the six months ended June 30, 2025 and 2024 represent 100% of the costs incurred, including those funded by our noncontrolling interest holder.
(2)Growth and maintenance capital expenditures related to our previously owned Alkali Business are associated with our discontinued operations and are not included in the table above.
Reconciliation of Income (loss) from continuing operations before income taxes to total Segment Margin:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Income (loss) from continuing operations before income taxes | $ | 10,356 |  |  | $ | (3,976) |  |  | $ | (26,061) |  |  | $ | 8,186 |
Net income attributable to noncontrolling interests | (10,417) |  |  | (7,357) |  |  | (19,186) |  |  | (14,960) |
Corporate general and administrative expenses | 15,068 |  |  | 19,405 |  |  | 56,744 |  |  | 34,616 |
Depreciation, amortization and accretion | 59,011 |  |  | 53,940 |  |  | 118,022 |  |  | 106,103 |
Interest expense, net | 60,754 |  |  | 64,539 |  |  | 130,792 |  |  | 126,873 |
Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income(1) | 5,595 |  |  | 4,879 |  |  | 11,687 |  |  | 11,687 |
Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value | (133) |  |  | (289) |  |  | (204) |  |  | (42) |
Other non-cash items | (4,229) |  |  | (2,474) |  |  | (6,951) |  |  | (4,601) |
Loss on extinguishment of debt (N ote 10) | 8,935 |  |  | 1,429 |  |  | 9,779 |  |  | 1,429 |
Differences in timing of cash receipts for certain contractual arrangements(2) | (9,071) |  |  | 7,820 |  |  | (17,358) |  |  | 15,892 |
Total Segment Margin | $ | 135,869 |  |  | $ | 137,916 |  |  | $ | 257,264 |  |  | $ | 285,183 |

(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)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.
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14. Transactions with Related Parties
The transactions with related parties were as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Revenues: |  |  |  |  |  |  |
Revenues from services and fees to Poseidon(1) | $ | 4,148 |  |  | $ | 6,025 |  |  | $ | 8,317 |  |  | $ | 11,008 |
Costs and expenses: |  |  |  |  |  |  |
Amounts paid to our CEO in connection with the use of his aircraft | $ | 165 |  |  | $ | 165 |  |  | $ | 330 |  |  | $ | 330 |
Charges for products purchased from Poseidon(1) | 266 |  |  | 298 |  |  | 542 |  |  | 584 |

(1)We own a 64% interest in Poseidon.
Our CEO, Mr. Grant E. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. 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 a private aircraft under long-term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement reflect what we would expect to obtain in an arms-length transaction.
Transactions with Unconsolidated Affiliates
Poseidon
We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement. Currently, that agreement automatically renews annually unless terminated by either party (as defined in the agreement). Our revenues for the three and six months ended June 30, 2025 include $2.7 million and $5.3 million, respectively, of fees we earned through the provision of services under that agreement. Our revenues for the three and six months ended June 30, 2024 include $2.6 million and $5.2 million, respectively, of fees we earned through the provision of services under that agreement. At June 30, 2025 and December 31, 2024, Poseidon owed us $3.8 million and $1.9 million for services rendered, respectively.
15. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.

| Six Months Ended June 30,
| 2025 |  | 2024
(Increase) decrease in: |  |  |
Accounts receivable | $ | (13,139) |  |  | $ | 73,043 |
Inventories | (26,318) |  |  | 40,761 |
Deferred charges | (22,185) |  |  | 6,497 |
Other current assets | (4,521) |  |  | 10,696 |
Increase (decrease) in: |  |  |
Accounts payable | 17,903 |  |  | (68,308) |
Accrued liabilities | (21,799) |  |  | (13,457) |
Net changes in components of operating assets and liabilities | $ | (70,059) |  |  | $ | 49,232 |

Payments of interest and commitment fees were $152.1 million and $113.5 million for the six months ended June 30, 2025 and 2024, respectively.
We capitalized interest of $14.8 million and $23.3 million during the six months ended June 30, 2025 and June 30, 2024, respectively.
At June 30, 2025 and 2024, we had incurred liabilities for fixed and intangible asset additions totaling $12.7 million and $38.8 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
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Condensed Consolidated Statements of Cash Flows. The amounts as of June 30, 2025 and 2024 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 (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 transportation and services 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 transportation and services product costs” in the Unaudited Condensed Consolidated Statements of Operations.
Balance Sheet Netting and Broker Margin Accounts
Our accounting policy is to offset over-the-counter derivative assets and liabilities executed with the same counterparty based on the contract settlement month. 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 derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. Margin requirements are intended to mitigate a party’s exposure to market volatility and counterparty credit risk. On a daily basis, our account equity (consisting of the sum of our cash margin balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin.
As of June 30, 2025, we had a net broker receivable of approximately $1.6 million (consisting of initial margin of $1.0 million increased by $0.6 million variation margin). As of December 31, 2024, we had a net broker receivable of approximately $0.9 million (consisting of initial margin of $1.1 million decreased by $0.2 million of variation margin). At June 30, 2025 and December 31, 2024, 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 June 30, 2025, we had the following outstanding derivative contracts that were entered into to economically hedge inventory and fixed price purchase commitments.

|  | Sell (Short) Contracts |  | Buy (Long) Contracts
Designated as hedges under accounting rules: |  |  |  |
Crude oil futures: |  |  |  |
Contract volumes (1,000 Bbls) |  | 197 |  |  | — |
Weighted average contract price per Bbl |  | $ | 62.71 |  |  | $ | — |
Not qualifying or not designated as hedges under accounting rules: |  |  |  |
Crude oil futures: |  |  |  |
Contract volumes (1,000 Bbls) |  | 85 |  |  | 103 |
Weighted average contract price per Bbl |  | $ | 67.44 |  |  | $ | 66.51 |
Crude oil swaps: |  |  |  |
Contract volumes (1,000 Bbls) |  | 40 |  |  | 40 |
Weighted average contract price per Bbl |  | $ | 61.91 |  |  | $ | 58.49 |
Crude oil options: |  |  |  |
Contract volumes (1,000 Bbls) |  | 30 |  |  | — |
Weighted average premium received/paid |  | $ | 0.09 |  |  | $ | — |

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Fair Value of Derivative Assets and Liabilities
The following tables reflect the estimated fair value position of our derivatives at June 30, 2025 and December 31, 2024:

| Unaudited Condensed Consolidated Balance Sheets Location |  | Fair Value
| June 30, 2025 |  | December 31, 2024
Asset Derivatives: |  |  |  |  |
Commodity derivatives - futures, swaps and options (undesignated hedges): |  |  |  |  |
Gross amount of recognized assets | Current Assets - Other(1) |  | $ | 294 |  |  | $ | 96 |
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets | Current Assets - Other(1) |  | (294) |  |  | (96) |
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) |  | $ | 555 |  |  | $ | 94 |
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets | Current Assets - Other(1) |  | (555) |  |  | (94) |
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets |  |  | $ | — |  |  | $ | — |
Liability Derivatives: |  |  |  |  |
Commodity derivatives - futures, swaps and options (undesignated hedges): |  |  |  |  |
Gross amount of recognized liabilities | Current Assets - Other(1) |  | $ | (113) |  |  | $ | (182) |
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets | Current Assets - Other(1) |  | 113 |  |  | 182 |
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets |  |  | $ | — |  |  | $ | — |
Commodity derivatives - futures (designated hedges): |  |  |  |  |
Gross amount of recognized liabilities | Current Assets - Other(1) |  | $ | (935) |  |  | $ | (637) |
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets | Current Assets - Other(1) |  | 935 |  |  | 637 |
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 within “Current Assets - Other”.
Effect on Operating Results

|  |  | Amount of Gain (Loss) Recognized in Income (Loss)
| Unaudited Condensed Consolidated Statements of Operations Location |  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Commodity derivatives - futures, swaps and options: |  |  |  |  |  |  |  |  |
Contracts designated as hedges under accounting guidance | Onshore transportation and services product costs |  | $ | 1,370 |  |  | $ | (59) |  |  | $ | 1,087 |  |  | $ | (2,977) |
Contracts not considered hedges under accounting guidance | Onshore transportation and services product costs |  | (455) |  |  | (44) |  |  | (542) |  |  | (286) |
Total commodity derivatives |  |  | $ | 915 |  |  | $ | (103) |  |  | $ | 545 |  |  | $ | (3,263) |

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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 June 30, 2025 and December 31, 2024.

|  | June 30, 2025 |  | December 31, 2024
Recurring Fair Value Measures |  | Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
Commodity and fuel derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Assets |  | $ | 849 |  |  | $ | — |  |  | $ | — |  |  | $ | 190 |  |  | $ | — |  |  | $ | — |
Liabilities |  | $ | (1,048) |  |  | $ | — |  |  | $ | — |  |  | $ | (819) |  |  | $ | — |  |  | $ | — |

Our commodity derivatives include exchange-traded futures. 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.
See Note 16 for additional information on our derivative instruments.
Other Fair Value Measurements
We believe the debt outstanding under our senior secured credit facility at June 30, 2025 and December 31, 2024 approximated its fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At June 30, 2025 and December 31, 2024, our senior unsecured notes had a carrying value of approximately $3.1 billion and $3.5 billion, respectively, and a fair value of approximately $3.2 billion and $3.5 billion, respectively. 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.
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; 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 from Continuing Operations of $10.0 million during the three months ended June 30, 2025 (the “2025 Quarter”) compared to Net Loss from Continuing Operations of $4.0 million during the three months ended June 30, 2024 (the “2024 Quarter”).
Net Income from Continuing Operations in the 2025 Quarter was impacted by: (i) an increase in operating income from our operating segments (see “Results of Operations” below for additional details); (ii) a decrease in interest expense, net, of $3.8 million (see “Results of Operations” below for additional details); and (iii) a decrease in general and administrative expenses of $3.6 million (see “Results of Operations” below for additional details) relative to the 2024 Quarter. These were partially offset by an increase in depreciation and amortization of $4.7 million during the 2025 Quarter (see “Results of Operations” below for additional details) and an increase in other expense of $7.5 million primarily related to the premium associated with the redemption of our 2027 Notes in April 2025 (see “Liquidity and Capital Resources” below for additional details).
We reported Net Income from Discontinued Operations, net of tax of $2.6 million during the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025.
Cash flow from operating activities was $47.0 million for the 2025 Quarter compared to $104.7 million for the 2024 Quarter. The decrease in cash flow from operating activities is primarily attributable to negative changes in working capital in the 2025 Quarter compared to the 2024 Quarter. In addition, cash flows provided by operating activities for the 2025 Quarter did not include activity from the Alkali Business, as it was sold on February 28, 2025, whereas the 2024 Quarter included a full quarter of activity from the Alkali Business.
Available Cash before Reserves (as defined below in “Non-GAAP Financial Measures”) to our common unitholders was $32.2 million for the 2025 Quarter, a decrease of $5.4 million, or 14%, from the 2024 Quarter primarily as a result of: (i) a decrease in Segment Margin of $2.0 million, which is discussed in more detail below; and (ii) the 2025 Quarter not including activity from the Alkali Business, as it was sold on February 28, 2025, whereas the 2024 Quarter included a full quarter of activity from the Alkali Business.
Segment Margin (as defined below in “Non-GAAP Financial Measures”) was $135.9 million for the 2025 Quarter, a decrease of $2.0 million, or 1%, from the 2024 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.
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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 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 (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters affecting international trade) aimed at addressing inflation or other conditions or events, 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, changes in governmental policies (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters) 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 considering the current industry environment and capital market behavior, we have continued our focus on deleveraging our balance sheet as further explained below in “Liquidity and Capital Resources.”
Results of Operations
Revenues and Costs and Expenses
Our revenues for the 2025 Quarter decreased $52.8 million, or 12%, from the 2024 Quarter and our total costs and expenses decreased $70.8 million between the two periods with an overall net increase to operating income of $18.0 million as presented on the Unaudited Condensed Consolidated Statements of Operations. The increase in our operating income during the 2025 Quarter is primarily due to: (i) an increase in operating income from our offshore pipeline transportation segment due to the contractual minimum volume commitments (“MVC’s”) on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the Shenandoah deepwater development and an increase in volumes on our CHOPS Pipeline primarily related to production from the Warrior and Winterfell projects, which produced first oil in late June 2024 and early July 2024, respectively; and (ii) a decrease in general and administrative expenses of $3.6 million (see further discussion below). These were partially offset by an increase in depreciation and amortization of $4.7 million during the 2025 Quarter (see further discussion below).
A substantial portion of our revenues and costs are derived from our onshore transportation and services segment, which includes the purchase and sale of crude oil in our crude oil marketing business as well as our other refinery-centric onshore operations. Additionally, our revenues and costs are derived from the operations within our offshore pipeline transportation segment and our marine transportation segment. We describe, in more detail below, the impact on revenues and costs for each of our businesses.
As it relates to our crude oil marketing business, the average closing price for West Texas Intermediate crude oil on the New York Mercantile Exchange (“NYMEX”) decreased to $64.57 per barrel in the 2025 Quarter, as compared to $81.81 per barrel in the 2024 Quarter. We expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil, resulting in a minimal direct impact on Net income (loss), Segment Margin and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil operations 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 impact on Net income (loss), Segment Margin and Available Cash before Reserves. However, we do have some indirect exposure to certain changes in prices for crude oil, 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.”
We also have revenues and costs associated with our other refinery-centric operations including our sulfur services business, which we believe is one of the largest producers and marketers of NaHS in North and South America, and from our other logistical assets including pipelines, trucks, terminals, and rail unloading facilities.
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We conduct our offshore crude oil and natural gas pipeline transportation and handling operations in the Gulf of America through our offshore pipeline transportation segment, which focuses on providing a suite of services 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 located primarily in offshore Texas, Louisiana and Mississippi. We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure and generate cash flows from fees to customers to utilize our assets. Our costs are primarily related to expenses incurred for the maintenance of our assets, employee compensation, and other operating costs.
Our marine transportation segment consists of (i) our inland marine fleet, which transports intermediate refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the U.S., primarily along the Mississippi River and its tributaries; (ii) our offshore marine fleet, which transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean; and (iii) our modern, double-hulled tanker, M/T American Phoenix. Our revenues are driven by the demand for our barge services and associated utilization of our fleets, as well as the day rates we charge, which can be dependent upon market conditions (including supply and demand in the market), amongst other factors. Our costs are principally related to the costs required to maintain our fleets, employee compensation, and other operating costs.
Refiners are the shippers of a majority o f the volumes transported on our onshore crude oil pipelines, and refiners contracted for approximately 80% of the revenues from our marine transportation segment during the 2025 Quarter, which are used primarily to transport intermediate refined products (not crude oil) between ref ining complexes. Given these facts, we do not expect changes in commodity prices to impact our Net income (loss), Segment Margin or Available Cash before Reserves derived from our offshore 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.
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. See “Non-GAAP Financial Measures” for further discussion surrounding total Segment Margin.
The contribution of each of our segments to total Segment Margin was as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
Offshore pipeline transportation | $ | 87,594 |  |  | $ | 86,131 |  |  | $ | 164,142 |  |  | $ | 183,937 |
Marine transportation | 29,817 |  |  | 31,543 |  |  | 59,838 |  |  | 62,906 |
Onshore transportation and services | 18,458 |  |  | 20,242 |  |  | 33,284 |  |  | 38,340 |
Total Segment Margin | $ | 135,869 |  |  | $ | 137,916 |  |  | $ | 257,264 |  |  | $ | 285,183 |

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A reconciliation of Income (Loss) from continuing operations before income taxes to total Segment Margin for the periods presented is as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Income (loss) from continuing operations before income taxes | $ | 10,356 |  |  | $ | (3,976) |  |  | $ | (26,061) |  |  | $ | 8,186 |
Net income attributable to noncontrolling interests | (10,417) |  |  | (7,357) |  |  | (19,186) |  |  | (14,960) |
Corporate general and administrative expenses | 15,068 |  |  | 19,405 |  |  | 56,744 |  |  | 34,616 |
Depreciation, amortization and accretion | 59,011 |  |  | 53,940 |  |  | 118,022 |  |  | 106,103 |
Interest expense, net | 60,754 |  |  | 64,539 |  |  | 130,792 |  |  | 126,873 |
Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income(1) | 5,595 |  |  | 4,879 |  |  | 11,687 |  |  | 11,687 |
Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value | (133) |  |  | (289) |  |  | (204) |  |  | (42) |
Other non-cash items | (4,229) |  |  | (2,474) |  |  | (6,951) |  |  | (4,601) |
Loss on debt extinguishment | 8,935 |  |  | 1,429 |  |  | 9,779 |  |  | 1,429 |
Differences in timing of cash receipts for certain contractual arrangements(2) | (9,071) |  |  | 7,820 |  |  | (17,358) |  |  | 15,892 |
Total Segment Margin | $ | 135,869 |  |  | $ | 137,916 |  |  | $ | 257,264 |  |  | $ | 285,183 |

(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)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.
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Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues | $ | 83,775 |  |  | $ | 80,577 |  |  | $ | 153,589 |  |  | $ | 161,982 |
Offshore natural gas pipeline revenue, excluding non-cash revenues | 13,210 |  |  | 11,507 |  |  | 26,005 |  |  | 25,837 |
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses | (26,590) |  |  | (22,395) |  |  | (50,764) |  |  | (43,153) |
Distributions from equity investments(1) | 17,199 |  |  | 16,442 |  |  | 35,312 |  |  | 39,271 |
Offshore pipeline transportation Segment Margin | $ | 87,594 |  |  | $ | 86,131 |  |  | $ | 164,142 |  |  | $ | 183,937 |
Volumetric Data 100% basis: |  |  |  |  |  |  |
Crude oil pipelines (average Bbls/day unless otherwise noted): |  |  |  |  |  |  |
CHOPS | 324,533 |  |  | 296,325 |  |  | 318,787 |  |  | 297,319 |
Poseidon | 248,785 |  |  | 280,248 |  |  | 246,566 |  |  | 286,085 |
Odyssey | 71,309 |  |  | 64,213 |  |  | 67,545 |  |  | 63,955 |
GOPL(2) | 1,383 |  |  | 1,465 |  |  | 1,532 |  |  | 1,911 |
Total crude oil offshore pipelines | 646,010 |  |  | 642,251 |  |  | 634,430 |  |  | 649,270 |
Natural gas transportation volumes (MMBtus/day) | 403,703 |  |  | 357,687 |  |  | 402,739 |  |  | 382,621 |
Volumetric Data net to our ownership interest(3): |  |  |  |  |  |  |
Crude oil pipelines (average Bbls/day unless otherwise noted): |  |  |  |  |  |  |
CHOPS | 207,701 |  |  | 189,648 |  |  | 204,024 |  |  | 190,284 |
Poseidon | 159,222 |  |  | 179,359 |  |  | 157,802 |  |  | 183,094 |
Odyssey | 20,680 |  |  | 18,622 |  |  | 19,588 |  |  | 18,547 |
GOPL(2) | 1,383 |  |  | 1,465 |  |  | 1,532 |  |  | 1,911 |
Total crude oil offshore pipelines | 388,986 |  |  | 389,094 |  |  | 382,946 |  |  | 393,836 |
Natural gas transportation volumes (MMBtus/day) | 104,638 |  |  | 102,701 |  |  | 104,734 |  |  | 109,940 |

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting for the three and six months ended June 30, 2025 and 2024.
(2)One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or “GOPL”) owns our undivided interest in the Eugene Island pipeline system.
(3)Volumes are the product of our effective ownership interest throughout the period multiplied by the relevant throughput over the given period.
Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Offshore pipeline transportation Segment Margin for the 2025 Quarter increased $1.5 million, or 2%, from the 2024 Quarter primarily due to several factors including: (i) the commencement of contractual MVC’s on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the deepwater Shenandoah development that began in June 2025 and contributed to our reported Segment Margin; and (ii) an increase in volumes on our CHOPS Pipeline primarily related to production from the Warrior and Winterfell projects, which produced first oil in late June 2024 and early July 2024, respectively. Production volumes from the Shenandoah floating production system (“FPS”) are life-of-lease dedicated to our 100% owned SYNC Pipeline and further downstream to our 64% owned CHOPS Pipeline. The Shenandoah FPS achieved first oil production in late July 2025, but we were able to recognize our MVC’s that began in the 2025 Quarter in Segment Margin. We expect the Shenandoah FPS to ramp up to its design capacity over the remainder of the year as the operator brings additional wells on-line.
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These increases to Segment Margin in the 2025 Quarter were partially offset by: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication; (ii) producer underperformance at several of the major fields attached to our pipeline infrastructure; and (iii) an increase in our operating costs. At the beginning of the third quarter of 2024, we reached the 10-year anniversary of a certain existing life-of-lease transportation dedication, which resulted in the contractual economic step-down of the associated transportation rate. In addition, there was an increase in producer downtime in the 2025 Quarter relative to the 2024 Quarter as a result of several wells being shut in due to certain sub-sea operational and technical challenges. The production from these wells impacted our results as they are molecules that we touch multiple times throughout our oil and natural gas pipeline infrastructure. Based on discussions with the producers from these impacted fields, the remediation work is nearing completion, and we expect production rates from these fields to, for the most part, return to more normalized rates by the end of the third quarter of 2025. Outside of these issues, activity in and around our Gulf of America asset base continues to be robust, including incremental in-field drilling at existing fields that tie into our infrastructure, and first oil from the Salamanca development, which is expected by the end of the third quarter of 2025.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Offshore pipeline transportation Segment Margin for the first six months of 2025 decreased $19.8 million, or 11%, from the first six months of 2024 primarily due to: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication; (ii) producer underperformance at several of the major fields attached to our pipeline infrastructure; and (iii) an increase in our operating costs. At the beginning of the third quarter of 2024, we reached the 10-year anniversary of a certain existing life-of-lease transportation dedication, which resulted in the contractual economic step-down of the associated transportation rate. In addition, there was an increase in producer downtime in the first six months of 2025 relative to the first six months of 2024 as a result of several wells being shut in due to certain sub-sea operational and technical challenges. The production from these wells impacted our results as they are molecules that we touch multiple times throughout our oil and natural gas pipeline infrastructure. Based on discussions with the producers from these impacted fields, the remediation work is nearing completion, and we expect a return to more normalized production rates from these fields in the third quarter of 2025.
These decreases to Segment Margin in the first six months of 2025 compared to the first six months of 2024 were partially offset by: (i) the commencement of contractual MVC’s on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the deepwater Shenandoah development that began in June 2025 and contributed to our reported Segment Margin; and (ii) an increase in volumes on our CHOPS Pipeline primarily related to production from the Warrior and Winterfell projects, which produced first oil in late June 2024 and early July 2024, respectively.
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Marine Transportation Segment
Within our marine transportation segment, we own a fleet of 87 barges (78 inland and 9 offshore) with a combined transportation capacity of 3.0 million barrels, 43 push/tow boats (33 inland and 10 offshore), and a 330,000 barrel capacity ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Revenues (in thousands): |  |  |  |  |  |  |
Inland freight revenues | $ | 34,252 |  |  | $ | 37,998 |  |  | $ | 67,462 |  |  | $ | 73,495 |
Offshore freight revenues | 30,784 |  |  | 26,054 |  |  | 61,776 |  |  | 53,350 |
Other rebill revenues(1) | 14,581 |  |  | 17,819 |  |  | 31,023 |  |  | 38,600 |
Total segment revenues | $ | 79,617 |  |  | $ | 81,871 |  |  | $ | 160,261 |  |  | $ | 165,445 |
Operating costs, excluding non-cash expenses (in thousands) | (49,800) |  |  | (50,328) |  |  | (100,423) |  |  | (102,539) |
Segment Margin (in thousands) | $ | 29,817 |  |  | $ | 31,543 |  |  | $ | 59,838 |  |  | $ | 62,906 |
Fleet Utilization:(2) |  |  |  |  |  |  |
Inland Barge Utilization | 98.1 | % |  | 100.0 | % |  | 95.9 | % |  | 100.0 | %
Offshore Barge Utilization | 97.3 | % |  | 94.9 | % |  | 96.8 | % |  | 97.0 | %

(1)Under certain of our marine contracts, we “rebill” our customers for a portion of our operating costs.
(2)Utilization rates are based on a 365-day year, as adjusted for planned downtime and dry-docking.
Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Marine transportation Segment Margin for the 2025 Quarter decreased $1.7 million, or 5%, from the 2024 Quarter. We experienced slightly lower utilization rates during the 2025 Quarter in our inland barge services primarily due to a slight decline in Midwest refinery demand for black oil equipment as a result of changing crude slates. This was partially offset by fewer dry-docking days in our offshore fleet during the 2025 Quarter and a higher contractual rate on our M/T American Phoenix in the 2025 Quarter as compared to the 2024 Quarter. Our offshore bluewater business began to experience pressure on day rates during the 2025 Quarter and as we entered the third quarter as certain third-party vessels were relocated to the East and Gulf coasts from the West Coast markets. While we did see some market challenges in the period, we still believe the fundamentals of our inland and offshore barge services are expected to remain strong through at least the remainder of the year.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Marine transportation Segment Margin for the first six months of 2025 decreased $3.1 million, or 5% from the first six months of 2024. We experienced slightly lower utilization rates during the first six months of 2025 in our inland barge services primarily due to a temporary decline in refinery utilization during the first quarter of 2025 and a slight decline in Midwest refinery demand for black oil equipment as a result of changing crude slates in the 2025 Quarter. This slight decline in Segment Margin was partially offset by fewer dry-docking days in our offshore fleet during the first six months of 2025 and a contractual rate increase on our M/T American Phoenix in the first six months of 2025 compared to the first six months of 2024. Our offshore bluewater business began to experience day rate pressure during the 2025 Quarter and as we entered the third quarter as certain third-party vessels were relocated to the East and Gulf coasts from the West Coast markets. While we did see some market challenges in the period, we still believe the fundamentals of our inland and offshore barge services are expected to remain strong through at least the remainder of the year.
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Onshore Transportation and Services Segment
Our onshore transportation and services segment includes terminaling, blending, storing, marketing, and transporting of crude oil and petroleum products, as well as the processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS,” commonly pronounced “nash”). Our onshore transportation and services segment utilizes an integrated set of pipelines, terminals, facilities, trucks and barges to facilitate the movement of crude oil, refined products, and other commodity products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals, rail unloading facilities, and refinery processing locations operating primarily within the U.S. Gulf Coast market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and bulk-purchased crude oil as well as the sale and delivery of NaHS and NaOH (also known as caustic soda) to customers. Through these assets we offer our customers a full suite of services, including the following as of June 30, 2025:
•facilitating the transportation of crude oil from producers and from our terminals, as well as those owned by third parties, to refineries via pipelines and trucks;
•purchasing/selling and/or transporting, storing, and blending 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, storing, and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets;
•unloading railcars at our crude-by-rail terminals;
•providing sulfur removal services from crude oil processing operations at refining or petrochemical processing facilities;
•operating storage and transportation assets in relation to our sulfur removal services; and
•selling NaHS and caustic soda to large industrial and commercial companies.
We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.
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Operating results from our onshore transportation and services segment were as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
Gathering, marketing and logistics revenue | $ | 112,256 |  |  | $ | 177,246 |  |  | $ | 256,235 |  |  | $ | 352,609 |
Crude oil pipeline tariffs and revenues | 6,565 |  |  | 6,669 |  |  | 11,490 |  |  | 13,767 |
Sulfur services revenues, excluding non-cash revenues | 35,585 |  |  | 43,487 |  |  | 73,438 |  |  | 85,890 |
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions | (92,611) |  |  | (159,443) |  |  | (220,374) |  |  | (319,584) |
Operating costs, excluding non-cash expenses | (42,639) |  |  | (50,198) |  |  | (88,060) |  |  | (98,066) |
Other | (698) |  |  | 2,481 |  |  | 555 |  |  | 3,724 |
Segment Margin | $ | 18,458 |  |  | $ | 20,242 |  |  | $ | 33,284 |  |  | $ | 38,340 |
Volumetric Data: |  |  |  |  |  |  |
Onshore crude oil pipelines (average Bbls/day): |  |  |  |  |  |  |
Texas | 98,626 |  |  | 65,229 |  |  | 80,377 |  |  | 74,923 |
Jay | 4,036 |  |  | 5,332 |  |  | 4,181 |  |  | 5,396 |
Mississippi | 1,059 |  |  | 2,789 |  |  | 1,124 |  |  | 2,800 |
Louisiana(1) | 48,178 |  |  | 56,172 |  |  | 43,203 |  |  | 64,514 |
Onshore crude oil pipelines total | 151,899 |  |  | 129,522 |  |  | 128,885 |  |  | 147,633 |
Crude oil product sales (average Bbls/day) | 15,366 |  |  | 21,702 |  |  | 17,655 |  |  | 22,570 |
Rail unload volumes (average Bbls/day) | 24,979 |  |  | 19,811 |  |  | 22,748 |  |  | 10,526 |
NaHS volumes (Dry short tons “DST”) | 23,256 |  |  | 29,656 |  |  | 49,129 |  |  | 58,693 |
NaOH (caustic soda) volumes (DST sold) | 8,678 |  |  | 10,593 |  |  | 17,223 |  |  | 20,951 |

(1)Total daily volumes for the three months ended June 30, 2025 and June 30, 2024 include 16,403 and 19,356 Bbls/day, respectively, of intermediate refined petroleum products and 31,775 and 36,269 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily volumes for the six months ended June 30, 2025 and June 30, 2024 include 17,500 and 24,766 Bbls/day, respectively, of intermediate refined petroleum products and 25,703 and 39,059 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.
Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Onshore transportation and services Segment Margin for the 2025 Quarter decreased $1.8 million, or 9%, from the 2024 Quarter primarily due to lower NaHS and caustic soda sales volumes. This decrease was partially offset by an increase in rail unload volumes at our Scenic Station facility and an overall increase in volumes on our onshore crude oil pipeline systems, principally driven by an increase in volumes on our Texas pipeline system, which is a key destination point for various grades of crude oil produced in the Gulf of America including those transported on our 64% owned CHOPS Pipeline.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Onshore transportation and services Segment Margin for the first six months of 2025 decreased $5.1 million, or 13%, from the first six months of 2024 primarily due to an overall decrease in volumes on our onshore crude oil pipeline systems and lower NaHS and caustic soda sales volumes. These decreases were partially offset by an increase in rail unload volumes at our Scenic Station facility.
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Other Costs, Interest and Income Taxes
General and administrative expenses

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
General and administrative expenses not separately identified below: |  |  |  |  |  |  |
Corporate | $ | 11,606 |  |  | $ | 14,498 |  |  | $ | 22,025 |  |  | $ | 26,276 |
Segment | 689 |  |  | 676 |  |  | 1,369 |  |  | 1,358 |
Long-term incentive compensation expense | 2,139 |  |  | 3,088 |  |  | 6,474 |  |  | 5,305 |
Third party costs related to business development activities and growth projects | 310 |  |  | 37 |  |  | 25,518 |  |  | 60 |
Total general and administrative expenses | $ | 14,744 |  |  | $ | 18,299 |  |  | $ | 55,386 |  |  | $ | 32,999 |

Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Total general and administrative expenses for the 2025 Quarter decreased by $3.6 million from the 2024 Quarter primarily due to the 2024 Quarter experiencing higher corporate general and administrative costs as a result of us conforming our short-term cash incentive programs to industry standards at that time.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Total general and administrative expenses for the first six months of 2025 increased by $22.4 million from the first six months of 2024. This increase is primarily due to the increase in third party costs related to business development activities and growth projects in the first quarter of 2025 as a result of the transaction costs incurred associated with the sale of the Alkali Business on February 28, 2025. This increase was partially offset due to the 2024 Quarter experiencing higher corporate general and administrative costs as a result of us conforming our short-term cash incentive programs to industry standards at that time.
Depreciation and amortization expense

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
Depreciation expense | $ | 53,347 |  |  | $ | 48,715 |  |  | $ | 106,947 |  |  | $ | 95,647 |
Amortization expense | 2,558 |  |  | 2,452 |  |  | 5,129 |  |  | 4,911 |
Total depreciation and amortization expense | $ | 55,905 |  |  | $ | 51,167 |  |  | $ | 112,076 |  |  | $ | 100,558 |

Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Total depreciation and amortization expense for the 2025 Quarter increased by $4.7 million from the 2024 Quarter. This increase is primarily attributable to our continued growth and maintenance capital expenditures and placing new assets into service, including our CHOPS expansion project, subsequent to the period ended June 30, 2024.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Total depreciation and amortization expense for the first six months of 2025 increased by $11.5 million from the first six months of 2024. This increase is primarily attributable to our continued growth and maintenance capital expenditures and placing new assets into service, including our CHOPS expansion project, subsequent to the period ended June 30, 2024.
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Interest expense, net

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in thousands) |  | (in thousands)
Interest expense, senior secured credit facility (including commitment fees), net | $ | 2,863 |  |  | $ | 5,600 |  |  | $ | 6,888 |  |  | $ | 15,001 |
Interest expense, senior unsecured notes | 63,952 |  |  | 68,047 |  |  | 134,490 |  |  | 129,628 |
Amortization of debt issuance costs, premium and discount | 1,378 |  |  | 2,861 |  |  | 4,256 |  |  | 5,547 |
Capitalized interest | (7,439) |  |  | (11,969) |  |  | (14,842) |  |  | (23,303) |
Interest expense, net | $ | 60,754 |  |  | $ | 64,539 |  |  | $ | 130,792 |  |  | $ | 126,873 |

Three Months Ended June 30, 2025 Compared with Three Months Ended June 30, 2024
Interest expense, net for the 2025 Quarter decreased by $3.8 million from the 2024 Quarter primarily due to a decrease in interest expense on our senior unsecured notes and a decrease in interest expense, net associated with our senior secured credit facility. The decrease in interest expense associated with our senior unsecured notes was primarily related to the redemption of our 2027 Notes on April 3, 2025. The decrease in interest expense, net associated with our senior secured credit facility during the 2025 Quarter was primarily a result of a reduction in the average borrowings outstanding during the period as a result of the proceeds received from the sale of the Alkali Business on February 28, 2025 and the immediate pay-down of the outstanding borrowings on our senior secured credit facility at that time.
These decreases were partially offset by a decrease in capitalized interest in the 2025 Quarter, which is primarily attributable to the completion of the CHOPS expansion project subsequent to the 2024 Quarter.
Six Months Ended June 30, 2025 Compared with Six Months Ended June 30, 2024
Interest expense, net for the first six months of 2025 increased by $3.9 million from the first six months of 2024 primarily due to an increase in interest expense on our senior unsecured notes and a decrease in capitalized interest. The increase in interest expense associated with our senior unsecured notes was primarily related to the issuance of our 7.875% senior unsecured notes due May 15, 2032 (the “2032 Notes”) in May 2024, which have a higher principal and interest rate as compared to our 6.25% senior unsecured notes due May 15, 2026 (the “2026 Notes”) that were redeemed in June 2024. The decrease in capitalized interest in the first six months of 2025 is primarily attributable to the completion of the CHOPS expansion project subsequent to June 30, 2024.
These increases were partially offset by lower interest expense on our senior secured credit facility during the first six months of 2025 as a result of a reduction in the average borrowings outstanding during the period as a result of the proceeds received from the sale of the Alkali Business on February 28, 2025 and the immediate pay-down of the outstanding borrowings on our senior secured credit facility at that time.
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 July 19, 2024, we entered into the Seventh Amended and Restated Credit Agreement (the “credit agreement”) to replace our Sixth Amended and Restated Credit Agreement. The credit agreement provides for a $900 million senior secured revolving credit facility that matures on September 1, 2028, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, provided that if more than $150 million of our 2028 Notes remain outstanding as of November 2, 2027, the credit agreement matures on such date.
On December 11, 2024 we entered into the First Amendment to the credit agreement, which resulted in several changes to the credit agreement terms including; (i) an increase of the maximum consolidated leverage ratio covenant from 5.50 to 1.00 to 5.75 to 1.00 for the fiscal quarters ending December 31, 2024 through September 30, 2025, returning to 5.50 to 1.00 thereafter; and (ii) changes to the minimum consolidated interest coverage ratio covenant from 2.40 to 1.00 to (A) 2.00 to 1.00 for the fiscal quarters ending December 31, 2024 through December 31, 2025, (B) 2.25 to 1.00 for the fiscal quarters ending March 31, 2026 through December 31, 2026, and (C) 2.50 to 1.00 for the remainder of the term.
On December 19, 2024, we issued $600.0 million in aggregate principal amount of our 8.000% senior unsecured notes due May 15, 2033 (the “2033 Notes”). The issuance of our 2033 Notes generated net proceeds of approximately $589 million, net of issuance costs incurred. We used the net proceeds to repurchase $575 million in principal of our 2027 Notes and pay a portion of the accrued interest and tender premium and fees on the notes that were validly tendered.
On February 28, 2025 we completed the sale of the Alkali Business to an indirect affiliate of WE Soda Ltd. for a gross purchase price of $1.425 billion. We received cash of approximately $1.0 billion, which reflects the net proceeds after the payment of transaction costs and expenses and the assumption of our then outstanding Alkali senior secured notes by an indirect affiliate of WE Soda Ltd. We used the cash proceeds to pay down the outstanding balance on our senior secured credit facility as of February 28, 2025, repurchase certain of our outstanding Class A Convertible Preferred Units (discussed further below), redeem a portion of our outstanding senior unsecured notes (discussed further below), and for general partnership purposes.
In connection with the sale of the Alkali Business, we also entered into the Second Amendment to the credit agreement. This amendment provides for: (i) a reduction from $900 million to $800 million of total borrowing capacity under our senior secured credit facility; (ii) unlimited cash netting against our outstanding debt for purposes of our consolidated leverage ratio calculation if our senior secured credit facility is undrawn at the end of a reporting period, otherwise a maximum netting of $25 million is allowed; and (iii) an increased permitted investment basket under certain circumstances that will allow us to opportunistically purchase existing private or public securities across our capital structure.
On March 6, 2025, we entered into purchase agreements with certain Class A Convertible Preferred unitholders whereby we purchased a total of 7,416,196 Class A Convertible Preferred Units at an average purchase price of $35.40 per unit. The purchase 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.
On April 3, 2025, using a portion of the cash proceeds from the sale of the Alkali Business, we redeemed the remaining $406.2 million of principal outstanding on the 2027 Notes, and paid the related accrued interest and redemption premium on those notes that were redeemed.
The successful completion of the above events, and in particular the sale of the Alkali Business, has kick-started the process of simplifying our capital structure, lowered our overall cost of capital and has resulted in no scheduled maturities of our senior unsecured notes or our senior secured credit facility until 2028. In addition, we have an ample amount of available borrowing capacity under our senior secured credit facility, subject to compliance with covenants in the credit agreement.
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, proceeds from the sale of assets, borrowing availability under our senior secured credit facility, the proceeds from issuances of equity (common and preferred) and senior unsecured or secured notes and the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.
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Our primary cash requirements consist of:
•working capital, primarily inventories and trade receivables and payables;
•routine operating expenses;
•growth capital (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.
In addition, 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 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. The Repurchase Program will be reviewed no later than December 31, 2026 and may be suspended or discontinued at any time prior thereto. During 2024 and 2025, we did not repurchase any Class A Common Units, and to date, we have purchased 114,900 Class A Common Units under the Repurchase Program.
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 June 30, 2025, the principal amount of long-term debt outstanding totaled approximately $3.2 billion, consisting of $71.6 million borrowed under our senior secured credit facility and $3.1 billion related to our senior unsecured notes. Our senior unsecured notes balance is comprised of $679.4 million of our 2028 Notes, $600.0 million of our 8.250% senior unsecured notes due January 15, 2029 (the “2029 Notes”), $500.0 million of our 8.875% senior unsecured notes due April 15, 2030 (the “2030 Notes”), $700.0 million of our 2032 Notes and $600.0 million of our 2033 Notes.
The available borrowing capacity under our senior secured credit facility at June 30, 2025 is $723.9 million, subject to compliance with covenants. Our inventory financing sublimit as of June 30, 2025 was $36.0 million of the maximum allowed of $200.0 million. Our credit agreement does not include a “borrowing base” limitation except with respect to our inventory loans.
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 “2024 Shelf”) on file with the SEC which we filed on April 16, 2024 to replace our existing universal shelf registration statement that expired on April 19, 2024. Our 2024 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 2024 Shelf is set to expire in April 2027.
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.
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The storage of our inventory of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil or petroleum products, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, 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 first six months of 2025 and the first six months of 2024.
Net cash flows provided by our operating activities for the six months ended June 30, 2025 were $71.8 million compared to $230.6 million for the six months ended June 30, 2024. The decrease in cash flows from operating activities is primarily attributable to a decrease in our reported Segment Margin and negative changes in working capital in the first six months of 2025 relative to the first six months of 2024. In addition, cash flows provided by operating activities for the first six months of 2025 only included activity from the Alkali Business prior to the sale on February 28, 2025, whereas the first six months of 2024 included a full period of activity from the Alkali Business.
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:

| Six Months Ended June 30,
| 2025 |  | 2024
| (in thousands)
Capital expenditures for fixed and intangible assets: |  |  |
Maintenance capital expenditures: |  |  |
Offshore pipeline transportation assets | $ | 5,460 |  |  | $ | 3,272 |
Marine transportation assets | 29,243 |  |  | 34,618 |
Onshore transportation and services assets | 4,054 |  |  | 5,752 |
Information technology systems and corporate assets | 654 |  |  | 861 |
Total maintenance capital expenditures | 39,411 |  |  | 44,503 |
Growth capital expenditures: |  |  |
Offshore pipeline transportation assets(1) | 53,676 |  |  | 115,857 |
Marine transportation assets | 209 |  |  | 7,224 |
Onshore transportation and services assets | 521 |  |  | 8,064 |
Information technology systems and corporate assets | — |  |  | 5,227 |
Total growth capital expenditures | 54,406 |  |  | 136,372 |
Total capital expenditures for fixed and intangible assets | 93,817 |  |  | 180,875 |
Capital expenditures related to equity investees | — |  |  | 285 |
Total capital expenditures(2) | $ | 93,817 |  |  | $ | 181,160 |

(1)Growth capital expenditures in our offshore pipeline transportation segment for 2025 and 2024 represent 100% of the costs incurred, including those funded by our noncontrolling interest holder (see further discussion below in “Growth Capital Expenditures”).
(2)Excluded from the table above were total capital expenditures of $6.4 million and $36.1 million for the six months ended June 30, 2025 and 2024, respectively, associated with the Alkali Business that was sold on February 28, 2025.
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Growth Capital Expenditures
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, Shenandoah and Salamanca, that have a combined production capacity of approximately 200,000 barrels per day. In conjunction with these agreements, we have incurred growth capital expenditures to expand the current capacity of our CHOPS Pipeline and construct the SYNC Pipeline.
Additionally, in 2023 and 2024, we entered into several additional definitive agreements with existing producers to further commit the volumes transported on our offshore pipeline infrastructure (including our SYNC Pipeline and CHOPS Pipeline). 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 credit agreement.
The CHOPS expansion includes a complete overhaul of the GB-72 topside facilities, reconnection of the CHOPS Pipeline to the GB-72 platform, and the addition of pumps at both the HI-A5 and GB-72 platforms to upgrade processing capabilities and increase throughput. During the fourth quarter of 2024, we completed the overhaul of the GB-72 topside facilities and reconnected the CHOPS Pipeline to the GB-72 platform and during the 2025 Quarter we completed the installation of the additional pumps at the HI-A5 and GB-72 platforms.
We have successfully laid the 105 miles of SYNC Pipeline and the Shenandoah FPS achieved first oil production in late July. As of the date of this filing we are successfully transporting crude oil on the SYNC pipeline.
Maintenance Capital Expenditures
Maintenance capital expenditures incurred during the first six months of 2025 and 2024 from our continuing operations primarily related to expenditures in our marine transportation segment to replace and upgrade certain equipment associated with our barge and fleet vessels during our dry-docks. Additionally, our offshore transportation assets require 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
In April 2025, we declared our quarterly distribution to our common unitholders of $0.165 per unit related to the first quarter of 2025. 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 were paid on May 15, 2025 to unitholders of record at the close of business on April 30, 2025.
In July 2025, we declared our quarterly distribution to our common unitholders of $0.165 per unit related to the 2025 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 on August 14, 2025 to unitholders of record at the close of business on July 31, 2025.
Guarantor Summarized Financial Information
Our $3.1 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by the Guarantor Subsidiaries, except for certain immaterial subsidiaries. The 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. 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 law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.
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The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.
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
| June 30, 2025
| (in thousands)
ASSETS(1): |
Current assets | $ | 556,449 |
Fixed assets, net | 2,210,315 |
Non-current assets | 716,578 |
LIABILITIES AND CAPITAL:(2) |
Current liabilities | 604,481 |
Non-current liabilities | 3,475,856 |
Class A Convertible Preferred Units | 552,523 |

Statement of Operations | Genesis Energy, L.P. and Guarantor Subsidiaries
| Six Months Ended June 30, 2025
| (in thousands)
Revenues(3) | $ | 666,797 |
Operating costs | 630,487 |
Operating income | 36,310 |
Loss from continuing operations | (79,439) |
Net loss(2) | (499,469) |
Net loss attributable to Genesis Energy, L.P. | (499,469) |

(1)Excluded from assets in the table above are net intercompany receivables of $96.7 million that are owed to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of June 30, 2025.
(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 $1.3 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the six months ended June 30, 2025.
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.
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Available Cash before Reserves for the periods presented below was as follows:

| Three Months Ended June 30,
| 2025 |  | 2024
| (in thousands)
Net loss attributable to Genesis Energy, L.P. | $ | (406) |  |  | $ | (8,744) |
Income tax expense | 345 |  |  | (11) |
Depreciation, amortization and accretion | 59,011 |  |  | 53,940 |
Plus (minus) Select Items, net | 3,195 |  |  | 11,937 |
Maintenance capital utilized(1) | (14,750) |  |  | (18,200) |
Cash tax expense | (300) |  |  | (300) |
Distributions to preferred unitholders | (14,868) |  |  | (21,894) |
Other non-cash items from discontinued operations(2) | — |  |  | 20,853 |
Available Cash before Reserves | $ | 32,227 |  |  | $ | 37,581 |

(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 2025 Quarter and 2024 Quarter were $16.8 million and $29.4 million, respectively, which excludes maintenance capital expenditures of $17.7 million in the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025.
(2)Includes non-cash items such as depreciation, depletion and amortization and unrealized gains or losses on derivative transactions, amongst other items.
We define Available Cash before Reserves (“Available Cash before Reserves”) as Net income (loss) attributable to Genesis Energy, L.P. before interest, taxes, depreciation, 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, interest expense, net, cash tax expense and cash distributions attributable 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 June 30,
|  | 2025 |  | 2024
|  | (in thousands)
I. | Applicable to all Non-GAAP Measures |  |  |
| Differences in timing of cash receipts for certain contractual arrangements(1) | $ | (9,071) |  |  | $ | 7,820 |
| Certain non-cash items: |  |  |
| Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value | (133) |  |  | (289) |
| Loss on debt extinguishment | 8,935 |  |  | 1,429 |
| Adjustment regarding equity investees(2) | 5,595 |  |  | 4,879 |
| Other | (4,229) |  |  | (2,474) |
| Sub-total Select Items, net | 1,097 |  |  | 11,365 |
II. | Applicable only to Available Cash before Reserves |  |  |
| Certain transaction costs | 310 |  |  | 37 |
| Other | 1,788 |  |  | 535 |
| Total Select Items, net(3) | $ | 3,195 |  |  | $ | 11,937 |

(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)Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(3)Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
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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 Income (loss) from continuing operations before income taxes 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. 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 (loss); 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) from our continuing operations. 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 CODM evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, and, where relevant, capital investment.
A reconciliation of Income (loss) from continuing operations before income taxes 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;
(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.
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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.
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.
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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 (including production rates and other conditions and events), future operating results, the ability to generate sales, income or cash flow, the timing and anticipated benefits of our development projects and the expected performance of our offshore assets and other projects and business segments, the ability to simplify our capital structure and lower our cost of capital, and the availability of borrowing capacity to fund our growth capital expenditures 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, and caustic soda, all of which may be affected by economic activity, capital expenditures and operational and technical issues experienced by energy producers, weather, alternative energy sources, international conflicts and international events (including the war in Ukraine, the Israel and Hamas war and broader geopolitical tensions in the Middle East and Eastern Europe), 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 or processing operations, 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 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 America or otherwise;
•the effects of future laws and regulations, including increased tariffs and proposed tariffs, taxes, duties and similar matters affecting international trade;
•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, the Israel and Hamas war and broader geopolitical tensions in the Middle East and Eastern Europe), 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.
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 as defined in Rules 13a-15(e) 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.
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There were no changes during the three months ended June 30, 2025 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. 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.
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 2025 Quarter.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
We sold our mine in Green River, Wyoming on February 28, 2025, and therefore are no longer required to provide information required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104).
Item 5. Other Information
None.
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Item 6. Exhibits.
(a) Exhibits

| 2.1# |  | Membership Interest Purchase Agreement, dated February 28, 2025, by and among Genesis Energy, L.P., Genesis Alkali Holdings, LLC, Genesis Alkali Holdings Company, LLC, Ciner Enterprises Inc., and WE Soda US LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated February 27, 2025, File No. 001-12295).
| 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 |  | 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).
| 3.4 |  | 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).
| 3.5 |  | 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).
| 3.6 |  | 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).
| 3.7 |  | 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).
* | 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.
| 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
# | Exhibits and Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K.

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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: | July 31, 2025 | By: | /s/ KRISTEN O. JESULAITIS
|  |  | Kristen O. Jesulaitis
|  |  | Chief Financial Officer
|  |  | (Duly Authorized Officer)

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