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e genesisenergy Genesis Energy , L.P. INVESTOR PRESENTATION August 2026 . NYSE : GEL
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Disclosures & Company Information Forward-Looking Statements & Non-GAAP Measures This presentation includes forward-looking statements as defined under federal law. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Actual results may vary materially. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future, including, but not limited to statements relating to future financial and operating results, liquidity and capital expenditures, distributions to our unitholders or other capital allocation plans or expectations, cost of capital and anticipated cash savings, the anticipated developments at Monument, Shenandoah and other production facilities or fields, production and other rates or volumes or demand for our services, the expected performance of our business segments and other projects, the impact of adverse producer events or challenges, proposed or increased tariffs or fluctuations in commodity prices on our business, and our strategy and plans, are forward-looking statements and historical performance is not necessarily indicative of future performance. Those forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside our control, that could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for products (which may be affected by the actions of OPEC and other oil exporting nations), impacts due to inflation, increased tariffs and proposed tariffs, taxes, duties and similar matters affecting international trade, a reduction in demand for our services resulting in impairments of our assets, the spread of disease, the impact of natural disasters, international military conflicts (such as the war in Ukraine and Iran and broader geopolitical tensions in the Middle East and Eastern Europe), the result of any economic recession or depression that has occurred or may occur in the future, anticipated benefits of our projects or those of our counterparties, including producers, the timing and success of business development efforts and other uncertainties. Those and other applicable uncertainties, factors and risks that may affect those forward-looking statements are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2025 filed with the Securities and Exchange Commission and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement. This presentation may also include certain non-GAAP financial measures. Please refer to our earnings release for the most directly comparable GAAP financial measures and the reconciliations of non-GAAP financial measures to GAAP financial measures included at the end of this presentation. Investor Relations Contact InvestorRelations@genlp.com (713) 860-2500 Corporate Headquarters 811 Louisiana, Suite 1200 Houston, TX 77002 2
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Genesis Energy, L.P. — At a Glance Three Market-Leading Business Segments — $647mm LTM Segment Margin Offshore Pipeline Transportation $444mm 69% of LTM Segment Margin • #1 deepwater crude pipeline operator in the central Gulf of America; irreplaceable at today's construction costs • Life-of-lease contracts; newer vintages add take-or-pay features and annual escalators • Multi-decade customer production profiles with low decline; extensive drilling inventory on existing leases Marine Transportation $109mm 17% of LTM Segment Margin • Modern, diversified fleet of Jones Act vessels focused on intermediate refined products • 33 push boats / 78 brown water barges ranging from 30-38k bbls • Nine ocean-going barges / ATBs ranging 65k–135k bbls • 330k bbl tanker American Phoenix on long-term contract through mid-2027 at a record day rate Onshore Transportation & Services $93mm 14% of LTM Segment Margin • Refinery-centric crude pipelines, terminals & sulfur removal units inside the refinery fence • Leading 3rd-party feedstock facilitator to ExxonMobil's Baton Rouge & Baytown refineries • Leading sulfur removal franchise; integrated NaHS / caustic soda footprint with steady cash flow $647mm LTM Total Segment Margin · Offshore 69% · Marine 17% · Onshore 14% Note: Segment Margin figures as of June 30, 2026. 3
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Investment Rationale Cash Flow Profile Poised to Deliver Increasing Returns to Stakeholders 1 Diverse, Long-Lived, Market-Leading Portfolio • 3 segments with high barriers to entry: Offshore Pipeline Transportation, Marine Transportation, and Onshore Transportation &Services • Significant operating leverage 2 Ample Liquidity & Significant Financial Flexibility • $900mm revolver extended to March 2031 (zero drawn at 6/30/26); nearest unsecured maturity in 2029 • Path to lower leverage over time: currently 5.0x → ~4.0x 3 Expected Adj. EBITDA Growth + Minimal Growth CapEx • Multi-year offshore producer-funded FPU expansions drive volume growth; zero growth capital currently planned by Genesis • Line of sight to growing free cash flow(a) over time 4 Attractive Current Yield with Earnings Growth • $0.20/unit common distribution (▲11% QoQ) • 3.2x distribution coverage in 2Q26 5 Disciplined Capital Allocation • 3-pronged capital allocation strategy: 1.) reduce debt in absolute terms, 2.) continue retiring high-cost preferred, and 3.) grow common unit distributions or purchase undervalued equity • ~$543mm of Class A preferred retired to date; ~$25mm/yr of financing savings achieved in 1H26 plus an additional $50-60mm/yr identified in potential additional financing savings Long-Lived Assets + Ample Liquidity + Adj. EBITDA Growth + Minimal CapEx + Capital Returns = Stakeholder Value Note: We are unable to provide a reconciliation of forward-looking Adjusted EBITDA, a non-GAAP measure, to its most directly comparable GAAP measure. (a) After certain cash obligations, including cash interest payments, preferred and existing common unit distributions, cash maintenance capital requirements, and cash taxes. 4
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Key Takeaways — 2Q 2026 Offshore Resilient; Long-Term Thesis Intact; Capital Structure Progressing $171.5mm Adj. EBITDA(a) 2Q 2026 $169.5mm Segment Margin 2Q 2026 $575-612mm FY26 Adj. EBITDA(a) Guidance Expect low-end of range as of 2Q 3.2x Common Unit Distribution Coverage $0.20 / quarter 5.0x 2Q26 Bank Leverage Ratio Long-Term Target ~4.0x O P E R A T IO NS O N- T R A CK Offshore Thesis Intact Visibility into multi-year dedicated volume growth; 2Q volumes slightly below expectations on operator unplanned downtime Monument, Shenandoah & Salamanca First Monument well on-line by year-end 2026, second in 1Q27; Additional wells at Shenandoah in 2027 and Shen. South in 2028; Salamanca steady at 40-42 kbd, 5th well late 2026 / early 2027 Marine at Full Capacity All four scheduled blue-water dry-dockings now complete; strong utilization and day rates exiting 2Q; Solid market fundamentals Onshore Outperformed Performed above expectations — steady Texas & Raceland volumes; legacy sulfur services performed in-line with expectations due to pulp & paper demand and NaHS supply 2 Q26 C A P IT A L S T R UC T UR E UP D A T E S $95mm Sale of non-core offshore natural gas assets $99.5mm Established accounts receivable facility at SOFR+1.375% ~$83mm Series A preferred repurchased; $311mm outstanding ~$3.6mm Repurchased 250,000 common units at WAP of $14.57 ~$25mm Future realized annual financing savings D IS C IP L IN E D C A P IT A L A L L O C A T IO N 1 Generate free cash flow(b) 2 Strengthen balance sheet 3 Redeem high-cost Series A preferred 4 Pay down debt & reduce leverage ratio 5 Thoughtfully grow common-unit distributions over time 6 Preserve flexibility to pursue attractive growth opportunities as they emerge Note: Bank leverage ratio as calculated under our senior secured credit facility. (a) Adjusted EBITDA is a non-GAAP financial measure; see reconciliations herein. (b) After certain cash obligations, including cash interest payments, preferred and existing common unit distributions, maintenance capital requirements, and cash taxes. 5
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I N V E S T O R P R E S E N T A T I O N · N Y S E : G E L Business Segment Detail Offshore Pipeline Transportation · Marine Transportation · Onshore Transportation & Services
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Offshore Pipeline Transportation — Overview World Class Footprint in Leading North American Basin • ~2,300 miles of pipelines and associated platforms primarily located in the Central Gulf of America • Leading independent midstream service provider uniquely positioned to give deepwater producers maximum optionality with access to both Texas and Louisiana markets • Focused on providing producers a “highway to shore” via CHOPS and Poseidon; laterals and associated infrastructure serve as feeder pipelines • Provide transportation to shore for several of the most prolific fields in the central Gulf of America C H O P S & P O S E ID O N V O L UM E S (K B D ) · +13 0 % S IN C E 2 0 1 2 308 351 393 432 467 467 437 499 425 453 464 581 565 614 695 710 38 0 20 40 60 80 100 120 140 160 0 100 200 300 400 500 600 700 800 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Q1 2026 Q2 2026 $ / bbl Kbd CHOPS & Poseidon Volumes (kbd) Hurricane Bridge Volumes (kbd) Avg. Crude Price (WTI, $/bbl) G E N E S IS O F F S H O R E C R UD E O IL P IP E L IN E S T O S H O R E CHOPS Poseidon Eugene Island Odyssey Q2 2026 Avg. Daily Volume ~397 kbd ~313 kbd NA ~62 kbd Delivery Point Texas Louisiana Louisiana Louisiana Mileage 380 367 184 120 Ownership 64% 64% 29% 29% Note: 2020 volumes adjusted ~38 kbd based on 28 days at an average of 490 kbd to reflect hurricane downtime. Average crude price per Energy Information Agency, WTI daily spot prices through June 30, 2026. 7
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Track Record of Success in the Gulf of America Driven by Strategic Acquisitions and Organic Growth 2010 $330mm — 50% interest in CHOPS acquired from Valero 2011 $206mm — Marathon GoA assets: 28% Poseidon · 23% Eugene Island · 29% Odyssey 2014 $197mm — SEKCO Pipeline completed (50/50 with Enterprise) 2015 $1.5B — Enterprise GoA assets: 50% CHOPS · 36% Poseidon · 50% SEKCO 2019 LLOG-operated Buckskin development on-line 2020 BP’s Atlantis Phase 3 & Talos’ Katmai first oil 2021 Sold 36% minority equity interest in CHOPS for $418mm 2022 Murphy's King's Quay FPS first oil LLOG’s Spruance development on-line 2023 BP’s Argos / Mad Dog 2 first oil — 100% dedicated to CHOPS 2024 Beacon’s Winterfell and Oxy’s Warrior developments on-line 2025 Beacon-operated Shenandoah first oil (SYNC/CHOPS); LLOG’s Salamanca first oil (SEKCO/Poseidon) 2026-28 Beacon’s Monument late '26 / early '27; Shenandoah South via subsea tieback in 2028 8
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Gulf of America – Crude Oil Production Continued Growth in the Deepwater • Deepwater GoA crude oil production is projected to increase ~91% from 2013 – 2027E • Growth driven by producers' ability to leverage existing infrastructure, improved drilling efficiency and lower service costs • New discoveries within ~30 miles of existing platforms are often “tied back” to utilize existing pipeline connectivity to shore • 48 new fields have started producing since 2015 — 33 are tiebacks to existing production facilities S E L E C T P R O D UC E R C O M ME NT A RY(b ) BP “The Argos Southwest Extension project…kicks off a period of significant growth for bp in the Gulf of America, which will continue to play a critical role in delivering secure and reliable energy the world needs today and tomorrow.” Chevron “Breakevens [in the Gulf of America] have come down a lot…We're now down in the teens and pushing to the low-teens on development costs…And so we've seen the breakevens there become very competitive, they had to because we had such good opportunities in other parts of our business. ” Talos “I think what's important is the fact that we have breakeven projects in the $30s to $40s a barrel that allows us to have robustness against the current price environment that we see.” Murphy “…the Khaleesi and Samurai wells were recently returned to production…These wells, because of their high production rates, are important cash flow generators and high rate- of-return investments. They also highlight the importance of the Gulf of America to the company’s production assets.“ Note: All pipeline capacity subject to producer crude quality. (a) Source: BSSE data and EIA’s July 7, 2026 short term energy outlook; 2020 production factors in hurricane days. (b) BP per 2Q25 earnings call; CVX 1Q25; Talos 1Q25; Murphy 2Q25. 9 G UL F O F A M E R IC A C R UD E O IL P R O D UC T IO N(a ) 1,258 1,399 1,515 1,605 1,682 1,759 1,899 1,672 1,707 1,732 1,865 1,790 1,900 1,990 1,890 $- $25 $50 $75 $100 $125 - 500 1,000 1,500 2,000 2,500 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024E 2025E 2026E 2027E $ / bbl kbd Non-Deepwater Deepwater (>1,000 ft.) Avg. Crude Price (WTI)
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Active Federal Leases in Gulf of America Proximity to Existing Leases Creates Stability and Future Opportunity • In April 2025, Interior and BOEM announced the 11th National OCS Oil and Gas Leasing Program — the foundation for future Gulf of America lease sales • Recent sales sit near our existing footprint, supporting long- term stability • Big Beautiful Gulf 1 and 2 lease sales were held on December 10, 2025 and March 11, 2026 – Big Beautiful Gulf 3 scheduled for August 12, 2026 $326mm+ combined high bids 206 tracts awarded 129 central GOA tracts awarded ~56% in the Central GOM Note: All pipeline capacity subject to producer crude quality. Central GOM covers Garden Banks, Green Canyon, Keathley Canyonand Walker Ridge planning areas. 10 Big Beautiful Gulf 1 & 2 lease sale statistics
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Ten Years of Gulf of America Leasing By the Numbers $2.66B Total high bids at sale day 15 sales, Mar 2016 – Mar 2026 2,377 Blocks that won a high bid one high bid per block $1.12mm Average high bid per block across the decade 41% Four core central deepwater areas as a share of total blocks won Note: All pipeline capacity subject to producer crude quality. Central GOA covers Garden Banks, Green Canyon, Keathley Canyonand Walker Ridge planning areas. 11 BBG3 8/12/26 $156 $18 $275 $121 $125 $178 $244 $159 $93 $121 $192 $264 $382 $279 $47 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1H 2016 2H 2016 1H 2017 2H 2017 1H 2018 2H 2018 1H 2019 2H 2019 1H 2020 2H 2020 1H 2021 2H 2021 1H 2022 2H 2022 1H 2023 2H 2023 1H 2024 2H 2024 1H 2025 2H 2025 1H 2026 2H 2026 Apparent high bids at sale day ($MM) % Central Gulf Planning-area sales Region-wide, 2017-2022 program IRA-mandated OBBBA % Central Gulf
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Central Gulf of America Overview Robust Inventory of Future Growth Note: All pipeline capacity subject to producer crude quality. Map not intended to be an exhaustive list of prospects. • Caesar / Tonga • Calpurnia • Genghis Khan • Holstein • K2 • Marco Polo • Tahiti Buckskin • Caicos • Khaleesi / Mormont • Samurai • Warrior • Wildling Atlantis / Atlantis Phase 3 Constellation Mad Dog / Mad Dog 2 Katmai / Katmai West Phobos Castile Hadrian North Leon Kaskida Sparta Gila Guadalupe Tiber Shenandoah Yucatan Coronado Selected Recent Developments / FIDs First OilProducerField 4Q ‘26 / Early ‘27BeaconMonument 1H 2027BeaconShenandoah Phase 2 2028BeaconShenandoah South Lucius Jack St. Malo Julia Big Foot Bullwinkle Lobster Cardamom Baldpate Constitution Ticonderoga Heidelberg Shenzi / Shenzi North AlleghenyDroshky Front Runner Delta House Ram Powell Petronius Nearly Headless Nick Stonefly Existing or Future Connection to Genesis Footprint Spruance Winterfell Tiberius SYNC Pipeline 12
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Case Study: Poseidon Oil Pipeline Irreplaceable Crude Oil Pipeline in the Central Gulf of America • Basin-critical pipeline transporting Central GoA production to key markets in Louisiana – Integrated onshore with Genesis' Raceland, LA terminal • In continuous operation for over 25 years — first oil in 1996; total gross PP&E to construct and maintain of $475mm as of 6/30/26 – Distributed on average ~$23mm per quarter to its owners over the last two years • Since 2012, volumes have increased ~48% across multiple commodity cycles • Recent developments on Poseidon: – Salamanca (Sept 2025) – Spruance (June 2022) – 50% of King's Quay (April 2022) – Buckskin (June 2019) • Substantially all contracts include “life of lease” dedications – Newer generation contracts also include take-or-pay commitments S T E A D Y V O L UM E S T H R O UG H C O M M OD IT Y C Y C L E S (K B D ) 211 207 210 260 263 254 235 265 291 263 257 306 278 257 270 313 0 20 40 60 80 100 120 140 0 50 100 150 200 250 300 350 400 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Q1 2026 Q2 2026 $ / bbl Kbd Poseidon Gross Daily Volumes (kbd) Avg. Crude Price (WTI, $/bbl) W O R L D C L A S S C US T O M ER B A S E Note: All pipeline capacity subject to producer crude quality. 13 Image result for equinor logo Image result for repsol logo Image result for hess logo Image result for eni logo Image result for exxonmobil logo
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Marine Transportation — Overview Structural Industry Tailwinds Driving Momentum • Modern, efficient fleet well positioned to benefit from steady demand and continued net retirements of Jones Act equipment – Demand driven by refinery utilization and crude differentials – Effectively no new construction • Day-rate charters with largely fixed costs and a high degree of operating leverage – Contract terms range from month-to-month to multi-year – American Phoenix operating under a 3.5-year contract through early-2027; contract is highest day rate under our ownership • Inland barges all asphalt capable; heated barges mostly in black oil service (~95%) Inland Fleet Offshore Fleet American Phoenix Capacity 30-38 kbbl 65-135 kbbl 330 kbbl Push Boats 33 9 - Barges 78 9 - Tankers - - 1 IN L A N D T A N K B A R G E S B Y A G E( a ) 959 823 572 372 272 207 21 153 238 0 200 400 600 800 1000 1200 0-5 5-10 10-15 15-20 20-25 25-30 30-35 35-40 >40 # of Barges Years >400 barges 30+ years old (candidates for retirement) O F F S H O R E B A R G E S B Y A G E(b) 4 32 43 116 45 14 6 2 0 20 40 60 80 100 120 140 160 0-5 5-10 10-15 15-20 20-25 25-30 30-35 35+ # of Barges Years 22 barges 25+ years old (candidates for retirement) (a) Per industry research. (b) Per industry & third-party sources as of November 2025. Includes tank barges with 75k-195k, <75k and >195,000 barrels of capacity. 14
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Onshore Transportation & Services — Overview Integrated Asset Footprint with Exposure to Significant Refinery Demand Baton Rouge Complex • Integral part of ExxonMobil's Baton Rouge refinery logistics and crude & intermediate products supply • Terminal capable of loading and unloading crude oil and VGO • Connectivity to deepwater import / export docks at Port of Baton Rouge • Multiple fee “touch points” across the integrated platform Texas City Terminal • Connection to Genesis owned and operated CHOPS pipeline • Destination point for various GoA grades including CHOPS / HOOPS • Downstream delivery includes ExxonMobil's Baytown refinery (via Webster) • Exploring additional downstream connectivity Raceland Terminal • Connection to Genesis owned and operated Poseidon pipeline • Downstream delivery to St. James, LA via LOCAP — connectivity to multiple South Louisiana refineries • Direct pipeline connection to ExxonMobil's North Line with delivery to XOM's Baton Rouge refinery Sulfur Services (dba TDC) • Leading producer and marketer of sodium hydrosulfide (“NaHS”) • Own and/or operate 11 separate “sour gas processing” units inside the refinery fence — AR, LA, MS, OK, TX, UT & WV • Downstream markets include copper mining, pulp & paper and other industrial applications across the Americas 15 Sulfur Services Poseidon CHOPS
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Sulfur Services — Facilitating Lower Emissions Market Leader of NaHS Production Helping Reduce Host Refinery Emissions What We Do • Leading producer of sodium hydrosulfide (“NaHS”) via 11 “sour gas processing” units inside the refinery fence – Proprietary process reacts high-H₂S gas with caustic soda (“NaOH”) – Running in parallel or in lieu of traditional sulfur removal units How We Make Money • Take sulfur in-kind as payment for removal services; sell NaHS primarily to large copper mining (North & South America), pulp & paper and other customers – Majority of contracts indexed to the price of NaOH – Also sell NaOH to refinery customers Competitive Advantages • Market-leading position with significant barriers to entry across asset, logistical and marketing footprints • Relationships with refineries and customers spanning 40+ years. • Consistent cash flow generation through economic cycles B US IN E S S O V E R V IE W 16 High H2S Gas Stream Clean Fuel Gas Chlor-Alkali Market Sodium Hydrosulfide (NaHS) Host Refiners Caustic Soda (NaOH) Closed Loop System Low Emissions Proprietary Sulfur Removal Technology NaHS Unit Copper Markets Pulp & Paper Markets Other Markets
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I N V E S T O R P R E S E N T A T I O N · N Y S E : G E L Appendix & Reconciliations Balance sheet detail, sustainability and non-GAAP reconciliations
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Balance Sheet Information Debt and Preferred Equity Profile $900mm Senior Secured Credit Facility Maturity: March 2031 2029 Nearest Unsecured Maturity No near-term re-financing risk 5.0x 2Q26 Bank Leverage Ratio Path to de-leveraging over time ~4.0x Target Bank Leverage Ratio Long-term target ~$311mm Series A Preferred Balance 11.24% · ~$543mm retired to-date D E B T M A T UR IT Y S C H E D UL E ($ M M ) 2026 2027 2028 $600 8.25% Notes 2029 $500 8.875% Notes 2030 2031 $700 7.875% Notes 2032 $600 8.00% Notes 2033 $750 6.75% Notes 2034 S IM P L IF IE D C A P IT A L S T R UC T UR E • 122,214,318 Class A Units; 39,997 Class B Units; no IDRs • 9,236,530 Series A Convertible Preferred Units • ~$3.2 Billion secured and unsecured debt P A T H F O R W A R D • Retire ~$311mm Series A preferred over time using free cash flow • Refinance unsecured notes as market conditions allow • Reduce bank leverage ratio over time Note: Number of common units, preferred units and outstanding balance assumed at par as of June 30, 2026. Bank leverage ratio as calculated under our senior secured credit facility. 18
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Sustainability at Genesis Supporting Business Priorities & Our Investors Through Sustainability • Committed to operating our business in a responsible and sustainable manner • Received “A” rating from MSCI in March 2026 • Released 2024 Sustainability Report on October 30, 2025 • Sale of soda ash business in February 2025 significantly reduced our pro-forma emissions footprint (see charts below) • Board and executive management engaged in review of sustainability program – Executive and key employee compensation connected to sustainability performance metrics • Long history of environmental stewardship combined with safe and reliable operations M S C I R A T IN G S H IS T O R Y CCC B BB BBB A AA AAA S C O P E 1 E M IS S IO NS (M M M e t r i c T o n s ) S C O P E 2 E M IS S IO NS (M M M e t r i c T o n s ) E M IS S IO N S IN T E N S IT Y (C O 2 e / $ MM R e v e n u e ) Note: Original emissions numbers as reported in Genesis previous sustainability reports. Pro-forma emissions numbers exclude legacy soda ash business that was sold on February 28, 2025. 19 0 500 1,000 1,500 2,000 2,500 3,000 3,500 2020 2021 2022 2023 CO2e Original Pro-Forma 0 100 200 300 400 2020 2021 2022 2023 CO2e Original Pro-Forma 0 500 1,000 1,500 2,000 2020 2021 2022 2023 Original Pro-Forma Nov-22 June-23 June-24 June-25 March-26 B BB BBB BBB A
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Balance Sheet & Credit Profile Leverage Ratio & Common Unit Distribution Coverage Ratio (a) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (inclu ding any unamortized discounts or issuance costs) less the amount outstanding under our inventory financing sublimit, and less c ash and cash equivalents on hand at the end of the period from our restricted subsidiaries. Adjusted Debt excludes amounts outstanding under our accounts receivable securitization credit facility, as permitted under o ur senior secured credit facility. (b) This amount reflects adjustments we are permitted to make under our senior secured credit facility for purposes of calculatin g compliance with our leverage ratio. (c) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior sec ured credit facility. 6 ($ in 000s) 6/30/2026 Senior secured credit facility - Senior unsecured notes, net of debt issuance costs and discount 3,104,316 Less: Outstanding inventory financing sublimit borrowings (17,100) Less: Cash and cash equivalents (38,921) Adjusted Debt (a) $3,048,295 Pro Forma LTM 6/30/2026 Consolidated EBITDA (per our senior secured credit facility) 593,436 Consolidated EBITDA Adjustments (b) 16,699 Adjusted Consolidated EBITDA (per our senior secured credit facility) (c) $610,135 Adjusted Debt / Adjusted Consolidated EBITDA 5.00x Q2 2026 Q2 2026 Reported Available Cash Before Reserves 78,316 Q2 2026 Common Unit Distributions 24,443 Common Unit Distribution Coverage Ratio 3.20x
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Reconciliations Segment Margin (a) Includes distributions attributable to the quarter and received during or promptly following such quarter. (b) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordanc e with GAAP on our related contracts. (c) During the three and six months ended June 30, 2026, we recognized a gain on the sale of assets of $17.4 million associated w ith the divestiture of certain non-core natural gas pipeline and platform assets within our offshore pipeline transportation segmen t. (d) See definition of Segment Margin in our 2Q 2026 earnings press release and Form 10 -Q. 6 ($ in 000s) 6/30/2026 3/31/2026 YTD 2026 3/31/2025 6/30/2025 9/30/2025 12/31/2025 2025 Income (loss) from continuing operations before income taxes 56,812 19,257 76,069 (36,417) 10,356 23,029 34,343 31,311 Net income attributable to noncontrolling interests (13,746) (12,345) (26,091) (8,769) (10,417) (13,569) (14,408) (47,163) Corporate general and administrative expenses 19,923 17,238 37,161 41,676 15,068 15,992 16,759 89,495 Depreciation, amortization and accretion 65,337 61,148 126,485 59,011 59,011 59,746 65,615 243,383 Interest expense, net 66,954 67,978 134,932 70,038 60,754 66,407 67,530 264,729 Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income (a) 2,468 5,521 7,989 6,092 5,595 5,233 4,989 21,909 Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value (770) 815 45 (71) (133) 136 (49) (117) Other non-cash items (3,769) (4,618) (8,387) (2,722) (4,229) (3,307) (5,318) (15,576) Loss on extinguishment of debt 30 3,540 3,570 844 8,935 - - 9,779 Differences in timing of cash receipts for certain contractual arrangements (b) (6,321) (2,094) (8,415) (8,287) (9,071) (7,091) 4,552 (19,897) Gain on sale of assets (c) (17,436) - (17,436) - - - - - Total Segment Margin(d) $169,482 $156,440 $325,922 $121,395 $135,869 $146,576 $174,013 $577,853
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Reconciliations Available Cash Before Reserves (a) Includes non-cash items such as depreciation, depletion and amortization and unrealized gains or losses on derivative transactio ns, amongst other non-cash items attributable to discontinued operations. (b) Refer to additional detail of Select Items in our 2Q 2026 earnings press release and Form 10 -Q. (c) See definition of Adjusted EBITDA in our 2Q 2026 earnings press release. (d) Maintenance capital expenditures for the 2026 Quarter and 2025 Quarter were $31.4 million and $16.8 million, respectively. Maintenance capital expenditures for the six months ended June 30, 2026 and 2025, were $48.1 million and $39.4 million, respective ly, which excludes maintenance capital expenditures of $4.6 million for the six months ended June 30, 2025 associated with our discontinued operations. Our continuing maintenance capital expenditures are principally as sociated with our marine transportation business. (e) Distributions attributable to preferred unitholders associated with the 2026 Quarter include $1.8 million paid during the 202 6 Quarter and $8.7 million that is payable on August 14, 2026 to unitholders of record at close of business on July 31, 2026. (f) Represents the Available Cash before Reserves to common unitholders. 6 ($ in 000s) 6/30/2026 3/31/2026 YTD 2026 3/31/2025 6/30/2025 9/30/2025 12/31/2025 2025 Net Income (Loss) Attributable to Genesis Energy, L.P. 42,857 6,800 49,657 (469,075) (406) 9,207 19,871 (440,403) Interest expense, net 66,954 67,978 134,932 70,038 60,754 66,407 67,530 264,729 Income tax expense 209 112 321 144 345 253 64 806 Depreciation, amortization and accretion 65,337 61,148 126,485 59,011 59,011 59,746 65,615 243,383 Loss from disposal of discontinued operations - - - 432,193 - - - 432,193 Interest expense, net and income tax expense from discontinued operations - - - 4,195 - - - 4,195 Other non-cash items from discontinued operations, net (a) - - - 15,584 - - - 15,584 EBITDA $175,357 $136,038 $311,395 $112,090 $119,704 $135,613 $153,080 $520,487 Plus (minus) Select Items, net (b) (3,824) 4,824 1,000 19,589 3,195 (3,656) 4,709 23,837 Adjusted EBITDA(c) $171,533 $140,862 $312,395 $131,679 $122,899 $131,957 $157,789 $544,324 Maintenance capital utilized (d) (15,450) (15,250) (30,700) (16,900) (14,750) (14,900) (14,950) (61,500) Interest expense, net (66,954) (67,978) (134,932) (70,038) (60,754) (66,407) (67,530) (264,729) Cash tax expense (300) (300) (600) (257) (300) (300) 624 (233) Distributions to preferred unitholders (e) (10,513) (13,565) (24,078) (19,942) (14,868) (14,868) (14,868) (64,546) Interest expense, net and income tax expense from discontinued operations - - - (4,195) - - - (4,195) Available Cash before Reserves(f) $78,316 $43,769 $122,085 $20,347 $32,227 $35,482 $61,065 $149,121 Common Unit Distributions 24,443 22,044 46,487 20,207 20,207 20,207 22,044 82,665 Common Unit Distribution Coverage Ratio 3.20x 1.99x 2.63x 1.01x 1.59x 1.76x 2.77x 1.80x
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Reconciliations Adjusted Debt & Adjusted Consolidated EBITDA (a) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (inclu ding any unamortized discounts or issuance costs) less the amount outstanding under our inventory financing sublimit, and less c ash and cash equivalents on hand at the end of the period from our restricted subsidiaries. Adjusted Debt excludes amounts outstanding under our accounts receivable securitization credit facility, as permitted under o ur senior secured credit facility. (b) This amount reflects adjustments we are permitted to make under our senior secured credit facility for purposes of calculatin g compliance with our leverage ratio. (c) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior sec ured credit facility. 6 ($ in 000s) 6/30/2026 3/31/2026 12/31/2025 Senior secured credit facility - 74,100 6,400 Senior unsecured notes, net of debt issuance costs and discount 3,104,316 3,102,076 3,040,415 Less: Outstanding inventory financing sublimit borrowings (17,100) (17,900) (28,100) Less: Cash and cash equivalents (38,921) (3,046) (6,318) Adjusted Debt (a) $3,048,295 $3,155,230 $3,012,397 Consolidated EBITDA (per our senior secured credit facility) 593,436 553,507 544,324 Consolidated EBITDA Adjustments (b) 16,699 33,473 43,773 Adjusted Consolidated EBITDA (per our senior secured credit facility)(c) $610,135 $586,980 $588,097 Adjusted Debt-to-Adjusted Consolidated EBITDA 5.00x 5.38x 5.12x
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Reconciliations Select Items (a) Includes the difference in timing of cash receipts from or billings to customers during the period and the revenue we recogni ze in accordance with GAAP on our related contracts. For purposes of our non -GAAP measures, we add those amounts in the period of p ayment and deduct them in the period in which GAAP recognizes them. (b) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us. (c) Represents Select Items applicable to all Non-GAAP measures. (d) Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves. 6 ($ in 000s) 6/30/2026 3/31/2026 YTD 2026 3/31/2025 6/30/2025 9/30/2025 12/31/2025 2025 Applicable to all Non-GAAP Measures Differences in timing of cash receipts for certain contractual arrangements (a) (6,321) (2,094) (8,415) (8,287) (9,071) (7,091) 4,552 (19,897) Certain non-cash items: Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value (770) 815 45 (71) (133) 136 (49) (117) Loss on debt extinguishment 30 3,540 3,570 844 8,935 - - 9,779 Adjustment regarding equity investees (b) 2,468 5,521 7,989 6,092 5,595 5,233 4,989 21,909 Other (3,769) (4,618) (8,387) (2,722) (4,229) (3,307) (5,318) (15,576) Sub-total Select Items, net (c) ($8,362) $3,164 ($5,198) ($4,144) $1,097 ($5,029) $4,174 ($3,902) Applicable only to Adjusted EBITDA and Available Cash before Reserves Certain transaction costs 3,944 3,122 7,066 25,208 310 329 1,110 26,957 Other 594 (1,462) (868) (1,475) 1,788 1,044 (575) 782 Total Select Items, net (d) ($3,824) $4,824 $1,000 $19,589 $3,195 ($3,656) $4,709 $23,837