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Elba LNG 1Q 2026 Investor Presentation February 2026
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Disclosure General – The information contained in this presentation does not purport to be all-inclusive or to contain all information that prospective investors may require. Prospective investors are encouraged to conduct their own analysis and review of information contained in this presentation as well as important additional information available on the Securities and Exchange Commission’s (“SEC”) EDGAR system at www.sec.gov and on our website at www.kindermorgan.com. Forward-Looking Statements – This presentation includes forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include any statement that does not relate strictly to historical or current facts and include statements accompanied by or using words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “target,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” and “long-term”. In particular, statements, express or implied, concerning future actions, conditions or events; long-term demand for our assets and services; energy demand growth and associated natural gas demand; capital projects, including expected costs, completion timing and benefits of those projects; energy-transition related opportunities, including opportunities related to alternative energy sources; our project backlog and opportunities beyond our project backlog; and future operating results such as our expectations for 2026 (including expected financial results, dividends, sustaining and discretionary capital expenditures and our financing and capital allocation strategy) are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do occur, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you are cautioned not to put undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments. 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 to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future, including, among others: commodity prices; the timing and extent of changes in the supply of and demand for the products we transport and handle; trends expected to drive new natural gas demand for electricity generation; national, international, regional and local economic, competitive, political and regulatory conditions and developments; the timing and success of open seasons and other business development efforts; our ability to obtain required permits and approvals for pending expansion projects when expected; the timing, cost, and success of expansion projects, including potential impacts of tariffs; our ability to consummate and realize the anticipated benefits of acquisitions; our ability to consummate proposed joint ventures; technological developments; the condition of capital and credit markets; inflation rates; interest rates; the political and economic stability of oil-producing nations; energy markets; federal, state or local income tax legislation; changes in policies affecting foreign trade and taxation, including tariffs, and potential adverse effects on financial and economic conditions; weather conditions; environmental conditions; business, regulatory and legal decisions; terrorism; cyber-attacks; and other uncertainties. Important factors that could cause actual results to differ materially from those expressed in or implied by forward-looking statements include the risks and uncertainties described in this presentation and in our Annual Report on Form 10-K for the year ended December 31, 2025, and our subsequent reports filed with the SEC (under the headings “Risk Factors,” “Information Regarding Forward-Looking Statements” and elsewhere). These reports are available through the SEC’s EDGAR system at www.sec.gov and on our website at www.kindermorgan.com. GAAP – Unless otherwise stated, all historical and estimated future financial information included in this presentation has been prepared in accordance with generally accepted accounting principles in the United States ("GAAP"). Non-GAAP – In addition to using financial measures prescribed by GAAP, we use non-generally accepted accounting principles (“non-GAAP”) financial measures in this presentation. Descriptions of our non-GAAP financial measures, and reconciliations to comparable GAAP measures, can be found in this presentation under “Non-GAAP Financial Measures and Reconciliations”. These non-GAAP financial measures do not have any standardized meaning under GAAP and may not be comparable to similarly titled measures presented by other issuers. As such, they should not be considered as alternatives to GAAP financial measures. Industry & Market Data – Certain data included in this presentation has been derived from a variety of sources, including independent industry publications, government publications and other published independent sources. Although we believe that such third-party sources are reliable, we have not independently verified, and take no responsibility for, the accuracy or completeness of such data. 2 Forward-Looking Statements / Non-GAAP Financial Measures / Industry & Market Data
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NGPL CP WIC CIG TCGT HXP EPNG Mojave Sierrita TX Intra KMLP MEP FEP NGPL TGP SNG EEC ELC GLNG FGT Stagecoach TGP PPL SFPP SFPP SFPP KMCC/ Double Eagle Cortez Wink Utopia Calnev Pipelines Pipelines Pipelines NATURAL GAS REFINED PRODUCTS CO2 Irreplaceable Infrastructure Portfolio 3 Note: Volumes per 2026 budget. Business mix based on 2026 budgeted Total Adjusted Segment EBDA, which is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. a) Does not include mileage associated with natural gas gathering assets. b) Refined Products includes 13% from our Products Pipelines Segment and 13% from our Terminals Segment. c) Annual capacity at KMI share. Delivering Energy. Improving Lives. Largest U.S. Natural Gas Transmission Network(a) — ~58,600 miles of transmission, ~6,800 miles of gathering, & 1,300 miles of NGL pipelines — Transport ~40% of U.S. natural gas production — >700 bcf of working storage capacity, ~15% of U.S. capacity One of the Largest CO2 Transporters in the U.S. — ~1,500 miles of CO2 pipelines with transport capacity of ~1.5 bcfd — Produce and transport CO2 for enhanced oil recovery (EOR) Strategic Renewable Natural Gas Portfolio — RNG production capacity of 6.4 bcf (c) 67% 26% 7% NATURAL GAS REFINED PRODUCTS (b) CO2 / EOR Fields RNG / Other Facilities16 Jones Act Tankers TerminalsStorage LNG Facilities BUSINESS MIX CO2 Largest U.S. Independent Refined Products Transporter & Terminal Operator — Transport ~1.7 mmbbld of refined product volumes — ~9,000 miles of refined products & crude pipelines — 136 liquids & bulk terminals; 16 Jones Act tankers — 135 mmbbl of total liquids storage capacity
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Driving Long-Term Shareholder Value 4 Natural Gas Focus 2/3 of cash flows come from midstream natural gas(a) Transport ~40% of U.S. natural gas production Predictable & Growing Cash Flows ~70% of cash flows are take-or-pay or hedged(a) +5% Adj. EPS and +2.5% Adj. EBITDA growth budgeted in 2026(c) Balance Sheet Strength ~3.8x YE 2026B Net Debt / Adjusted EBITDA BBB+ / Baa2 (positive) investment grade balance sheet(b) Attractive Growth Projects ~$10.0 billion of committed projects at <6x EBITDA build multiple Pursuing >$10 billion of additional opportunities beyond our current backlog Shareholder Returns Increasing dividend for 9th straight year Returned nearly $23 billion to shareholders over the past 10 years(d) Note: Total Adjusted Segment EBDA, Adjusted EPS, Adjusted EBITDA, Net Debt, and EBITDA build multiple (calculated based on Project EBITDA) are non-GAAP financial measures. See Non-GAAP Financial Measures & Reconciliations. a) Based on 2026 budgeted Total Adjusted Segment EBDA. b) S&P and Fitch have KMI’s senior unsecured rating at BBB+. Moody’s has KMI’s senior unsecured rating at Baa2 with a positive outlook. c) The final 2026 budget includes the impact of the EagleHawk divestiture, which closed after our preliminary guidance announcement in December. d) 2016 – 2025 dividends and share repurchases. $
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Highly Contracted, Predictable Cash Flows 5Note: Cash flow mix based on 2026 budgeted Total Adjusted Segment EBDA, which is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. Includes hedging as of 1/16/2026. CASH FLOW MIX Take-or-Pay 65% Unhedged 4% Fee-Based 26% Hedged 5% 65% Take-or-Pay • Entitled to payment regardless of throughput • Reservation fee for capacity 26% Fee-Based • Fixed fee collected regardless of commodity price • Volumetric based revenues • ~40% highly stable, refined product cash flows 5% Hedged • Disciplined approach to managing price volatility • Substantially hedged near-term price exposure 4% Unhedged • Commodity price based 96% Take-or-Pay, Fee-Based, or Hedged Cash Flows
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Proven project execution underpins confidence in delivering our $10.0 billion backlog at a <6x EBITDA build multiple Successfully Achieving Attractive Returns 6 INVESTMENT MULTIPLES ACHIEVED Total Invested Capital / Year 2 EBITDA (a) Demonstrated Project Execution Provides Foundation for Delivering Future Returns a) Multiple reflects KMI share of invested capital divided by Project EBITDA, a non-GAAP measure (see Non-GAAP Financial Measures & Reconciliations), generated in its second full year of operation. G&P projects are excluded from the investment multiple but included in all other statistics. CO2 EOR projects are excluded from all statistics. b) Based on cumulative U.S. PPI Final Demand inflation between November 2020 – November 2025. c) Project returns reflect the capital-weighted average IRR for projects placed in service between 2021 – 2025. 273 projects placed in service 2021-2025, representing nearly $5.4 billion of capital Total capex within 0.5% of original estimate, despite a backdrop of 26% cumulative inflation(b) Vast majority of projects completed on time and on budget or better Currently expect project returns(c) to be within 100bps from original expectations and well above our cost of capital 4.4x 4.5x 2021 – 2025 Projects Completed Original Estimate Actual Multiple or Current Estimate ~0.1x Variance to Original Estimate
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$10.0bn Committed Growth Capital Project Backlog as of 12/31/2025 7 ~20% of Backlog Capital Going into Service During 2026 Note: Figures may not sum due to rounding. Other includes projects in our Products Pipelines and Terminals Segments. EBITDA build multiple reflects KMI share of estimated capital divided by estimated Project EBITDA (a non-GAAP financial measure). See Non-GAAP Financial Measures & Reconciliations. $ Billion Total Natural Gas (excluding G&P) $8.3 Nearly all serving end-use power, LDC, and LNG demand Other 0.3 Primarily refined product projects Subtotal $8.6 Contracted, stable cash flows, minimal direct commodity exposure EBITDA Build Multiple ~5.6x Gathering & Processing 0.8 Mostly natural gas, volume-based projects EOR 0.5 Commodity price & volume-based cash flows Total Backlog $10.0 ~90% Natural gas portion of backlog 1Q 2028 Capital-weighted average project in-service date >$3 billion Expected annual growth capex over next few years
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Total Backlog $10.0 billion Natual Gas Segment $9.1 billion Transmission Projects $8.3 billion Power Demand $5.7 billion LNG Demand $2.1 billion G&P $0.8bn $0.9bn PROJECT BACKLOG COMPOSITION High-Quality Growth Within Our Core Competency 8 ~80% of Backlog Tied to Serving Power & LNG Demand Note: Figures may not sum due to rounding. Project EBITDA is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. a) Total project capital from 2016 – 2025. KMI share $8.5 billion. b) Includes 14 projects with capital investment >$100 million, collectively representing ~90% of our $9.1 billion Natural Gas Pipelines Segment project backlog. Metrics shown are capital-weighted. S&P/Moody's/Fitch blended credit rating. Other Segments Projects are primarily extensions off our existing network Completed $13 billion of natural gas pipelines and storage over the past 10 years (a) Other $0.4bn Growth underpinned by highly contracted, long- lived, take-or-pay pipeline and storage projects Across our largest natural gas projects, >90% of capacity is contracted, with an average tenor of >20 years & average customer credit rating of A- (b) Pursuing >$10 billion of additional natural gas opportunities beyond our backlog, all within areas of our core expertise HIGH - QUALITY PROJECTS MORE TO COME CORE COMPETENCY
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321 343 389 410 541 2010 2015 2020 2024 2050 Global Natural Gas Demand Poised for Long-Term Growth 9 U.S. LNG Well Positioned to Meet Global Demand Source: IEA (2025) World Energy Outlook Current Policies Scenario, World Energy Outlook 2025 – Analysis – IEA. All rights reserved. GLOBAL NATURAL GAS DEMAND bcfd Demand growth largely coming from countries with limited domestic natural resources Additional U.S. LNG will be needed to meet growing global demand Abundant supply at a competitive cost Low geopolitical risk Established transport & storage infrastructure ✓ KEY U.S. ADVANTAGES ✓ ✓ ~130 bcfd of Global Demand Growth by 2050 (This is Greater than Total Current U.S. Natural Gas Market)
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110 115 120 125 130 135 140 2025 2026 2027 2028 2029 2030 Extensive Network Well Positioned to Serve Growing U.S. Natural Gas Demand 10 KMI Wood Mackenzie +19 bcfd +26 bcfd U.S. NATURAL GAS DEMAND bcfd New Infrastructure Will Be Needed to Support Rising Demand 58,600 39,400 30,900 21,500 16,700 14,400 13,400 8,400 8,100 7,500 KMI Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Scale and Connectivity of Our Footprint Will Enable Us to Capture Future Growth U.S. NATURAL GAS TRANSMISSION PIPELINE MILEAGE BY OPERATOR (a) Source: KMI internal natural gas forecast as of 1Q 2026. Wood Mackenzie North America Gas 10-Year Investment Horizon Outlook, November 2025. a) Data per recent peer company reports and presentations. Does not include mileage associated with gathering assets. Peers include Berkshire, Boardwalk, ENB CN, EPD, ET, OKE, Tallgrass, TRP CN, and WMB. Variance reflects KMI’s higher demand outlook for LNG & Power +5 bcfd +2 bcfd
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Bakken Powder River DJ Green River Uinta - Piceance San Juan Anadarko Permian Eagle Ford Haynesville Marcellus Utica Gas Storage LNG Terminal LNG Feedgas +13 bcfd • Rising global demand for U.S. LNG • Abundant, economic U.S. natural gas supply Power +3 bcfd • Growth driven by population migration, economic development, coal-to-gas conversions, manufacturing re-shoring, & data centers • New capacity needed to backstop intermittent renewables Industrial +2 bcfd • Growth primarily along the TX & LA Gulf Coast Residential & Commercial stable • Steady, primarily weather-driven demand Mexico Exports stable • KMI can deliver into Mexico at multiple strategic points Storage • Becoming increasingly important to support variable demand • KMI has >700 bcf of working storage capacity 11 2025 U.S. Demand 115 bcfd Increase in demand by 2030 +19 bcfd Source: Wood Mackenzie North America Gas 10-Year Investment Horizon Outlook, November 2025. Industrial sector includes Wood Mackenzie’s “Other” category, comprised of lease and plant fuel. LNG feedgas equals exports plus an assumed 9% increase for plant fuel. This volume would otherwise be included in the Industrial category. 2030 demand growth includes 1 bcfd from Transport and Blue Hydrogen; sectors not broken out above. Numbers may not sum due to rounding. WoodMac Natural Gas Demand Overview: 2025 – 2030 >85% of Growth is Expected to Occur in Texas & Louisiana, Driven by LNG Exports 1 5 2 3 4 1 1 1 2 2 2 2 2 2 2 2 2 2 4 4 4 4 4 5 5 2 3
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MEP SNG SNG TGP TGP TGP NGPL NGPL TX Intra KMLP Rio Grande Corpus Christi Freeport Delfin LNG Sabine Pass Golden Pass Port Arthur Louisiana LNG Cameron Calcasieu Pass Commonwealth Plaquemines Agua Dulce Katy Henry KMI Contracted LNG Export Terminals Other Proposed/Existing LNG Export Terminals Market Hub MississippiLouisiana Texas 16 18 20 23 25 29 2025 2026 2027 2028 2029 2030 LNG Exports Driving Natural Gas Demand Growth Our Assets Are Well Positioned to Supply Robust LNG Export Growth Along the Texas and Louisiana Gulf Coast WOODMAC U.S. LNG FEEDGAS FORECAST bcfd KMI has long-term contracts to move 8 bcfd to LNG facilities today & >12 bcfd by the end of 2028 >20% of contracted $10.0bn project backlog directed toward serving LNG demand Actively pursuing additional opportunities 12 Elba Express KMI-Elba IslandGeorgia South Carolina Note: Wood Mackenzie North America Gas 10-Year Investment Horizon Outlook, November 2025. LNG feedgas equals exports plus an assumed 9% increase for plant fuel. 3rd Party EPNG Costa Azul California Arizona Mexico Mojave Mexico
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Population Migration & Economic Growth Coal-to-Gas Conversions Industrial Re-shoring Renewable Backup Data Center Demand Actively Pursuing >10 bcfd of Additional Power Opportunities Growing Power Needs Boosting Demand for Natural Gas Source: Population growth per the U.S. Census Bureau; State Population Totals and Components of Change: 2020-2024. Southern U.S. includes Arizona, New Mexico, Texas, Arkansas, Louisiana, Tennessee, Mississippi, Alabama, South Carolina, Georgia, and Florida. Coal-fired power plant and 2025 generation data per the EIA. AI driven capex figure per McKinsey. 13 INCREASING NATURAL GAS FIRED POWER DEMAND DRIVEN BY Natural gas is a crucial backup source for renewable energy – providing dispatchable, lower- emission power to balance intermittent renewables Coal accounts for ~17% of U.S. power generation ~45 coal-fired power plants slated for retirement located within 50 miles of our pipelines Re-shoring manufacturing increases the need for consistent, high- capacity power Dependable natural gas fired power is essential for must-run data centers Majority of growth likely to occur in the Southern U.S. Population growth in the Southern U.S. 2x the rest of the country Growth largely occurring within our geographic footprint ~60% of contracted $10.0bn project backlog directed to power generation & utility demand Substantial customer interest for additional capacity Global AI driven capex to average >$1tn annually through 2030
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45 65 85 105 125 145 165 20° 30° 40° 50° 60° 70° 80° Natural gas demand for a given degree day continues to rise Increased demand has magnified at the extremes Driven by decreasing baseload coal generation and growing intermittent renewable generation Increased pipeline and storage capacity needed to serve growing peak demand Top 2 all-time record days for natural gas demand occurred in January 2025 Rising Need for Natural Gas Amid Growing Market Volatility 14 Source: Point Logic, American Gas Association. a) Includes residential, commercial, industrial, and power demand. LOWER 48 NATURAL GAS DEMAND (a) VS. AVERAGE DAILY TEMPERATURE Natural Gas Demand (bcfd)(a) Average Daily Temperature (ºF) Weather-driven demand highlights the growing need for natural gas deliverability to support energy stability 2025 2015 Demand sensitivity to temperature swings rose 50% between 2015 & 2025
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Vast, Low-Cost U.S. Supply Meeting Growing Demand While Maintaining Reasonable Prices 15Source: Supply data per Wood Mackenzie’s North America Gas 10-Year Investment Horizon Outlook, November 2025. Pricing per Bloomberg. - $1 $2 $3 $4 $5 $6 $7 $8 - 20 40 60 80 100 120 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 U.S. NATURAL GAS SUPPLY & PRICE Natural Gas Supply (bcfd) Average Natural Gas Price ($/mmbtu) Supply Price U.S. Natural Gas Supply Has Increased >70% since 2010 Prices Have Remained Range-Bound Between $2 ‒ $4 Russia-Ukraine War U.S. reserves are vast and low cost, given continued upstream efficiency gains New supply can be accessed with minimal upward pressure on market price
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Bakken Powder River DJ Green River Uinta - Piceance San Juan Anadarko Permian Eagle Ford Haynesville Marcellus Utica Northeast +7 bcfd • Production constrained by egress despite ample, low-cost supply 1 Haynesville +7 bcfd • Abundant, low-cost, low-nitrogen supply • Key to serving Gulf Coast demand markets Permian +5 bcfd • Supply grows as oil production increases & gas-oil ratios rise • Vital to supplying the Desert Southwest, Gulf Coast, and Mexico Eagle Ford(a) +1 bcfd • Potential upside to forecast; critical supply link to Gulf Coast • Important source of low-nitrogen gas for LNG facilities Rockies +0.5 bcfd Bakken/DJ/Powder River • Serves Rockies and West Coast demand Gas Storage LNG Terminal 2025 U.S. Production 108 bcfd Increase in supply by 2030 +20 bcfd WoodMac Natural Gas Supply Overview: 2025 – 2030 16 Source: Wood Mackenzie North America Gas 10-Year Investment Horizon Outlook, November 2025. a) Eagle Ford outlook includes production from the Austin Chalk. b) Total reserves per the Colorado School of Mines Potential Gas Committee. Years of remaining production calculated based on Wood Mackenzie’s 2025 U.S. production forecast. >100 Years of U.S. Natural Gas Supply Remaining at Current Production Rates(b) 1 5 2 3 4 2 1 3 4 5 5 5
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WIC CP NGPL CIG TCGT Mojave EPNG Sierrita TX Intra MEP KMLP FEP SNG FGT EEC TGP Stagecoach Utopia ELC GLNG Gas Storage LNG Terminal HXP (c) Natural Gas Segment Overview 17 Connecting Key Natural Gas Resources with Major Demand Centers Largest Natural Gas Transmission Network in the U.S. (a) a) Does not include mileage associated with natural gas gathering assets. b) Includes deliveries in Arizona, New Mexico, Texas, Arkansas, Louisiana, Tennessee, Mississippi, Alabama, South Carolina, Georgia, and Florida. c) Hiland Express is being converted from crude oil service to NGL service, expected to be in service end of Q1 2026. ~40% of all feedgas deliveries to U.S. LNG facilities ~50% of all U.S. natural gas exports to Mexico ~45% of all direct- connect natural gas deliveries to Southern U.S. power plants(b) Areas with high forecasted natural gas fired power demand growth KMI Transports ~40% of U.S. Natural Gas Production • Irreplaceable, Long - Lived Infrastructure • Primarily Transmission & Storage Assets • Gathering & Processing Assets in Key Basins • Robust Opportunity Set for Growth 7,600 miles Intrastate Transmission Pipelines 1,300 miles NGL Pipelines 51,000 miles Interstate Transmission Pipelines >700 bcf Working Gas Storage Capacity 6,800 miles Gathering Pipelines 4,865 bbtud expected volumes in 2026
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5.4 6.7 2016 2025 years years SNG 5.8 7.8 2016 2025 years years5.3 7.3 2016 2025 Rising Demand Benefitting Our Natural Gas Transmission Business 18 WOODMAC U.S. NATURAL GAS DEMAND bcfd INCREASED TENOR AND/OR RATES NEW PROJECTS INCREASED PIPELINE USAGE FACTOR (a) TX INTRASTATES(b) EPNG ~$9.1 billion of natural gas projects in our backlog; expect to continue adding projects over time(c) years years INCREASED DEMAND LEADING TO EXAMPLES 74% 90% 79 115 134 2016 2025 2030 +44% +17% Source: Wood Mackenzie North America Gas 10-Year Investment Horizon Outlook, November 2025. a) Represents the capacity weighted average usage factor of TGP, EPNG, NGPL, SNG, and the Texas Intrastates collectively. Usage factor is calculated as billed throughput divided by average annual designed pipeline capacity. b) TX Intrastates average remaining contract life includes term sale portfolio. c) Total includes ~$0.8bn of natural gas gathering & processing projects. 2016 5 - Pipe Average 2025 5 - Pipe Average
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Major Projects Capital(a) ($bn) Capacity (bcfd) In-Service Date Primary Driver South System Expansion 4 SNG & EEC $1.8 1.3 4Q28, 4Q29 Power Trident (Phase I & II)(b) TX Intrastates $1.8 2.0 1Q27, 4Q28 LNG Mississippi Crossing TGP $1.7 2.1 2Q28 Power Phase IX FGT $0.6 0.6 4Q28 Power Plantation North Expansion KinderHawk $0.5 1.0 4Q26 G&P Bridge EEC $0.4 0.3 2Q30 Power Cumberland TGP $0.2 0.2 1Q26 Power North Extension NGPL $0.2 0.2 4Q28 Power GCX Expansion TX Intrastates $0.2 0.6 2Q26 Supply Push Hiland Express Pipeline Double H Crude Pipeline $0.2 -- 1Q26 NGL Conversion ~$9.1 Billion of Approved Natural Gas Projects Note: Project EBITDA is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. a) KMI share of estimated project capital for our 10 largest Natural Gas Pipelines Segment projects. Includes Allowance for Funds Used During Construction (AFUDC). b) Expect Trident to generate ~30% of its full run-rate contracted Project EBITDA in 2027 and ~80% in 2028 due to staggered contract start dates. 19 1 1 Gas Storage LNG Terminal 3 1 2 3 7 6 1 8 2 3 4 5 6 7 9 10 2 8 Bakken Powder River DJ Green River Uinta - Piceance San Juan Anadarko Permian Haynesville Marcellus Utica 10 Eagle Ford 10 5 9 9 4 4 4 Pursuing >$10 Billion of Additional Opportunities Beyond Our Current Backlog
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Natural gas storage Marcellus/Utica egress Exports to Mexico TX, LA, & LNG Exports Midwes t Northeast Southeast Desert Southwest Front Range Haynesville Marcellus/ Utica Eagle Ford Permian Rockies Premier Network Positioned to Meet Growing Natural Gas Opportunity 20 Pursuing >$10bn of Opportunities Beyond Our Current Backlog Gulf Coast LNG exports TX & LA power & industrial Desert Southwest power Midwest power Exports to Mexico Southeast power Haynesville egress KMI Natural Gas Storage Production Basin Demand Center KMI Natural Gas Pipeline Natural Gas Supply Flow Bakken ~90% of Future Opportunities Driven by Power & LNG Demand
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Camino Real Hiland Crude KMCC HSC Galena Park Double Eagle Splitter Calnev West Line East Line Oregon Line PPL (SE) CFPL NY Harbor San Diego Line North Line Note: Adjusted Segment EBDA and Terminals and Product Pipelines FCF are non-GAAP financial measures. See Non-GAAP Financial Measures & Reconciliations. Figures may not sum due to rounding. 2022 – 2024 Adjusted Segment EBDA amounts are adjusted to reflect categorization of basis difference amortization (amortization of excess cost of equity investments) consistent with 2025 Segment EBDA accounting change. Jones Act Tankers Products Pipelines Segment & Terminals Segment Overview 21 Both Segments Principally Refined Products Focused Liquids Terminals Bulk Terminals Terminals Segment Bulk Terminals 24 Liquids Terminals 47 Capacity ~79 mmbbl Jones Act 16 tankers Refined Products Terminals Transmix Facilities Crude Pipelines Crude Terminals Condensate Splitter Products Pipelines Segment Pipelines ~9,000 miles Terminals 65 Capacity ~56 mmbbl Transmix 5 facilities RD Capacity ~87 mbbld Refined Products Pipelines $1.1 $1.1 $1.2 $1.2 $1.2 $1.0 $1.0 $1.1 $1.1 $1.1 $2.0 $2.1 $2.3 $2.3 $2.3 2022 2023 2024 2025 2026B Products Pipelines Segment Terminals Segment TERMINALS & PRODUCTS PIPELINES ADJUSTED SEGMENT EBDA $ Billions >$11bn of Adjusted Segment EBDA & >$8bn of FCF Generated Over 5 Years
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$0.5 $0.4 $0.3 $0.3 $0.3 $0.3 $0.3 $0.3 $0.3 $0.2 $0.8 $0.7 $0.6 $0.6 $0.5 2022 2023 2024 2025 2026B FCF Capex Acquisitions Adj. Segment EBDA Note: CO2 EOR & Transport FCF and Adjusted Segment EBDA are non-GAAP financial measures. See Non-GAAP Financial Measures & Reconciliations. 2022 – 2024 Adj. Segment EBDA amounts are adjusted to reflect categorization of basis difference amortization (amortization of excess cost of equity investments) consistent with 2025 Segment EBDA accounting change. SACROC includes Diamond M acreage. a) Includes sustaining and expansion capital expenditures. 22 CO2 Segment: EOR and Transport Overview World Class, Fully-Integrated Assets Consistently Generating Robust Free Cash Flow Interest in 3 oil fields with 8.8 billion barrels of Original Oil In Place Interest in 3 CO2 fields with 37 tcf of Original Gas In Place ~1,500 miles of CO2 pipelines with capacity to move up to 1.5 bcfd CO2 pipelines CO2 source fields Oil fields Crude pipelines Permian basin CO 2 EOR & TRANSPORT FREE CASH FLOW $ Billions >$1.5 billion FCF Generated Over 5 years (a) SACROC McElroy Yates Wink Bravo Dome Doe Canyon McElmo Dome New Mexico Colorado Texas El Paso
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CCS • Evaluating commercial opportunities across the CCS value chain • Leveraging decades of CO2 experience to become a leading provider of CO2 transportation and sequestration services RNG • Established a strategic RNG platform • 6 facilities with 6.4 bcf(a) of RNG production capacity; contracted long term into the transportation market • Focused on optimizing operations; potential for longer-term expansion opportunities Future Opportunities • Focused on areas synergistic with KMI’s expertise and significant set of diversified assets 23a) Annual capacity at KMI share. CO2 Segment: Energy Transition Ventures (ETV) Group Overview Pursuing Economic Lower Carbon Energy Opportunities CO2
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Committed to Being a Good Steward 24 Investing in Lower Carbon Fuels Leak Detection Employee Development Reduce & Avoid Methane Emissions Continuous Improvement 100% of our natural gas compressor stations surveyed annually 283 Participants in our leadership training $ 9.1 bn Natural gas focused(a) BB → AAA MSCI score improvement 2018 – 2025 ~10% Reduction in methane emissions intensity since 2022 Dedicated to Doing Business the Right Way, Every Day ‒ Serving Our Investors, Our Colleagues, Our Customers, and Our Neighbors to Improve Lives and Create A Better World $ Note: Values shown are for 2024 unless otherwise indicated. a) Natural Gas Pipelines Segment projects included in our 12/31/2025 backlog.
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Sustainability Ratings Recognition 25Note: MSCI ESG rating, Sustainalytics ESG risk rating, Refinitiv ESG score rank, FTSE ESG score as of January 2026. MSCI AAA Oil & Gas Refining, Marketing, Transportation & Storage Industry Sustainalytics Top 10% out of 87 Oil & Gas Storage & Transportation Companies & 170 Refiners & Pipelines Refinitiv #8 of 239 Oil & Gas Related Equipment & Services Companies FTSE #3 of Oil & Gas Pipelines subsector Highly Rated By Multiple Agencies z Included in Several Sustainability Indices FTSE4Good, S&P 500 Scored and Screened, JULCD, MSCI Climate & ESG Indices
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APPENDIX KinderHawk Elm Grove Facility
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Take-or-Pay or Hedged Volumes & price are contractually fixed Fee-Based Price is fixed, volumes are variable Commodity- Price Based Avg. remaining contract term as of 12/31/2025 Additional cash flow security Natural Gas Interstate / LNG 40% 3% 6.6 / 14.7 years Tariffs are FERC-regulated TX Intrastate 13% 3% 7.3 years G&P 1% 6% 1% 5.0 years Primarily acreage dedications for fee-based contracts Products Refined products 1% 8% 1% generally not applicable Pipeline tariffs are FERC-regulated ~73% of 2026B Products Adj. Segment EBDA has an annual inflation-linked tariff escalator Crude transport 1% 1% 3.8 years(b) Crude G&P 1% Terminals Liquids terminals 5% 2% 1.7 years ~76% of 2026B Terminals Adj. Segment EBDA has annual price escalators (inflation-linked or fixed-price escalators) Bulk terminals: primarily minimum volume guarantee or requirements Jones Act tankers 3% 3.3 years Bulk terminals 2% 1% 4.6 years CO2 EOR Oil & Gas 3% 1% CO 2 & Transport 1% 1% 5.5 years with third parties Commodity-price based contracts are mostly minimum volume committed ETV 1% 70% 26% 4% Contract Strategy Insulates Cash Flows Through Commodity Cycles 27 Note: Total Adjusted Segment EBDA is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. TX Intrastate average remaining contract life includes term sale portfolio. a) Hedged cash flows. b) Includes Condensate Splitter. (a) Long-Term, Secure Cash Flows Minimize Price & Volume Volatility (a) (a)
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Use of Non-GAAP Financial Measures Our non-GAAP financial measures described below should not be considered alternatives to GAAP net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes. Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses), or (iii) align the timing of impacts from natural gas inventory hedges with the future associated physical withdrawals from inventory. We also include adjustments related to joint ventures (see “Amounts associated with Joint Ventures” below). Adjusted Net Income Attributable to Kinder Morgan, Inc. is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to Kinder Morgan, Inc. Adjusted Net Income Attributable to Common Stock is calculated by adjusting net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. For periods from 2017 to 2018, also reflects an adjustment for preferred stock dividends. We believe Adjusted Net Income Attributable to Common Stock allows for calculation of Adjusted EPS on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculated as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over- period performance and ability to generate earnings that are core to our ongoing operations. Adjusted Segment EBDA is calculated, for an individual segment, by adjusting segment earnings before DD&A, general and administrative expenses and corporate charges, interest expense, and income taxes (Segment EBDA) for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. Total Adjusted Segment EBDA is calculated as the sum of all our segments' respective Adjusted Segment EBDA or, to the extent that a segment has no reportable Certain Items, Segment EBDA. Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. before interest expense, income taxes, DD&A, and amortization of basis differences related to our joint ventures (EBITDA) for Certain Items. For periods from 2017 to 2019, Adjusted EBITDA also reflects an adjustment for Kinder Morgan Canada Limited noncontrolling interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts associated with Joint Ventures” below). Adjusted EBITDA (on a rolling 12-months basis) is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. 28
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Use of Non-GAAP Financial Measures (Continued) Amounts associated with Joint Ventures – Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures (JVs) and consolidated JVs utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests (NCI),” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated JVs include the same adjustments (DD&A, amortization of basis differences and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the JVs as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. Although these amounts related to our unconsolidated JVs are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated JVs. Net Debt is calculated by subtracting from debt (1) cash and cash equivalents, (2) debt fair value adjustments, and (3) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA (on a rolling 12-months basis) as part of a ratio of Net Debt-to-Adjusted EBITDA, that is used by management, investors, and other external users of our financial information to evaluate our leverage. For periods from 2017 to 2018, Net Debt also reflects subtraction of the preferred interest in the general partner of Kinder Morgan Energy Partners, L.P. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most comparable measure to Net Debt is total debt. DCF, or Distributable Cash Flow, is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts associated with Joint Ventures” above). DCF is used by us to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. Project EBITDA, which we use to calculate EBITDA build multiples, is calculated for an individual capital project as earnings before interest expense, taxes, DD&A and general and administrative expenses attributable to such project, or for JV projects, consistent with the methods described above under “Amounts associated with Joint Ventures,” and in conjunction with capital expenditures for the project. Management, investors and others use Project EBITDA to evaluate our return on investment for capital projects before expenses that are generally not controllable by operating managers in our business segments. We believe the GAAP measure most directly comparable to Project EBITDA is the portion of net income attributable to a capital project. We do not provide the portion of budgeted net income attributable to individual capital projects (the GAAP financial measure most directly comparable to Project EBITDA) due to the impracticality of predicting, on a project-by-project basis through the second full year of operations, certain amounts required by GAAP, such as projected commodity prices, unrealized gains and losses on derivatives marked to market, and potential estimates for certain contingent liabilities associated with the project completion. Acquisition EBITDA Multiples – With respect to projected EBITDA multiples associated with acquired assets or businesses, we do not provide the portion of budgeted net income attributable to individual acquisitions (the GAAP financial measure most directly comparable to projected EBITDA for acquired assets or businesses) due to the impracticality of predicting certain amounts required by GAAP, such as projected commodity prices, unrealized gains and losses on derivatives marked to market, and potential estimates for certain contingent liabilities associated with the acquisition. FCF, or Free Cash Flow, is calculated by reducing cash flow from operations for capital expenditures (sustaining and expansion), and FCF after dividends is calculated by further reducing FCF for dividends paid during the period. FCF is used by management, investors and other external users as an additional leverage metric, and FCF after dividends provides additional insight into cash flow generation. We believe the GAAP measure most directly comparable to FCF is cash flow from operations. CO2 EOR & Transport, Terminals and Product Pipelines Free Cash Flow is calculated by reducing Segment EBDA from our CO2 EOR & Transport assets, and our Terminals and Products Pipelines segments by Certain Items, capital expenditures (sustaining and expansion) and acquisitions attributable to the EOR & Transport assets, Terminals, and Products Pipelines segment. Management uses CO2 EOR & Transport, Terminals, and Product Pipelines Free Cash Flow as an additional performance measure for our CO2 EOR & Transport assets, Terminals, and Products Pipelines segment. We do not provide budgeted CO2 EOR & Transport, Terminals, and Products Pipelines Segment EBDA (the GAAP financial measure most directly comparable to 2025 budgeted CO2 EOR & Transport, Terminals, and Product Pipelines FCF) due to the inherent difficulty and impracticability of predicting certain amounts required by GAAP, such as potential changes in estimates for certain contingent liabilities and unrealized gains and losses. 29
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2026 2025 Change Budget Actual $ % Net income attributable to KMI 3,066$ 3,056$ 10$ 0% Certain Items(a) Risk management activities - (29) 29 100% Gain on divestitures - (123) 123 100% Estimated gain on miscellaneous land sale (29) - (29) n/a Income tax Certain Items 6 (2) 8 400% Other - (3) 3 100% Total Certain Items (23) (157) 134 85% Adjusted Net income attributable to KMI 3,043$ 2,899$ 144$ 5% Net income attributable to KMI 3,066$ 3,056$ 10$ 0% Total Certain Items(a) (23) (157) 134 85% DD&A 2,536 2,453 83 3% Income tax expense(b) 895 834 61 7% Cash taxes (33) (45) 12 27% Sustaining capital expenditures (944) (937) (7) (1%) Amounts associated with joint ventures Unconsolidated JV DD&A(c) 370 391 (21) (5%) Remove consolidated JV partners' DD&A (63) (63) - - Unconsolidated JV income tax expense(d)(e) 83 89 (6) (7%) Unconsolidated JV cash taxes(d) (86) (78) (8) (10%) Unconsolidated JV sustaining capital expenditures (178) (175) (3) (2%) Remove consolidated JV partners' sustaining capital expenditures 9 9 - - Other items(f) 13 29 (16) (55%) DCF 5,645$ 5,406$ 239$ 4% Weighted average shares outstanding for dividends(g) 2,237 2,236 1 0% DCF per share(h) 2.52$ 2.42$ 0.10$ 4% 30 Net Income, Adjusted Net Income Attributable to KMI, and DCF Note: Adjusted Earnings and Distributable Cash Flow (DCF), in aggregate and per share, are non-GAAP financial measures. See Non-GAAP Financial Measures and Reconciliations. a) See “Non-GAAP Financial Measures—Certain Items.” b) To avoid duplication, amounts are adjusted to exclude amounts which are already included within “Certain Items” above. c) Includes amortization of basis differences related to our JVs. d) Associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments. e) Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above. See table included in “Non-GAAP Financial Measures—Certain Items.” f) Includes non-cash compensation associated with our restricted stock program, non- cash pension expense and pension contributions. g) Includes 11 million and 13 million average unvested restricted shares that participate in dividends in 2026 and 2025, respectively. h) 2026 Budget DCF per share of $2.52 consists of the following quarterly amounts: Q1 $0.73, Q2 $0.55, Q3 $0.58, Q4 $0.67. $ in Millions
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2017 2018 2019 2020 2021 2022 2023 2024 2025 2026B Net income attributable to KMI 183$ 1,609$ 2,190$ 119$ 1,784$ 2,548$ 2,391$ 2,613$ 3,056$ 3,066$ NCI associated with Certain Items - - - - - - - - - - Certain Items(a) Fair value amortization (53) (34) (29) (21) (19) (15) - - - - Legal, environmental and other reserves (37) 12 46 26 160 51 - - - - Risk management activities 40 80 (24) (5) 19 57 (126) 72 (29) - Loss on impairment/Gain on divestitures 170 317 (280) 1,927 1,535 - 67 (69) (123) (29) Impact of 2017 Tax Cuts and Jobs Act 219 (36) - - - - - - - - Income tax Certain Items 1,085 (58) 299 (107) (491) (37) 33 (52) (2) 6 Noncontrolling interests - 240 (4) - - - - - - - Other 21 (20) (37) 72 16 32 45 7 (3) - Total Certain Items 1,445 501 (29) 1,892 1,220 88 19 (42) (157) (23) Preferred stock dividends (156) (128) - - - - - - - - Net income allocated to participating securities (b) (5) (8) (12) (13) (14) (13) (14) (15) (16) (15) Other(c) (1) (2) - - (3) (1) - 1 1 - Adjusted Net Income Attributable to Common Stock 1,466$ 1,972$ 2,149$ 1,998$ 2,987$ 2,622$ 2,396$ 2,557$ 2,884$ 3,028$ - - Weighted average shares outstanding 2,230 2,216 2,264 2,263 2,266 2,258 2,234 2,220 2,223 2,226 Adjusted EPS 0.66$ 0.89$ 0.95$ 0.88$ 1.32$ 1.16$ 1.07$ 1.15$ 1.30$ 1.36$ 31 Reconciliation of Adjusted Net Income Attributable to Common Stock and Adjusted EPS a) See “Non-GAAP Financial Measures—Certain Items.” b) Net income allocated to participating securities is based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings, as applicable. c) Adjusted net income in excess of distributions for participating securities. $ in Millions
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Reconciliation of Terminals FCF 2022 2023 2024 2025 2026B EBDA for Terminals(a) 975$ 1,039$ 1,099$ 1,143$ 1,172$ Certain items(b) Loss (gain) on impairments, divestitures and other write-downs, net - - - - (29) Other - - - - - Segment Certain Items - - - - (29) Adjusted EBDA for Terminals 975 1,039 1,099 1,143 1,143 Capital expenditures (GAAP)(c) (552) (406) (385) (326) (400) Acquisitions - - - - - Terminals FCF 423$ 633$ 714$ 817$ 743$ Reconciliation of Products Pipelines FCF EBDA for Products Pipelines (a) 1,072$ 1,033$ 1,164$ 1,157$ 1,206$ Certain items(b) Legal, environmental and other reserves - - - - - Risk management activities - (1) - 1 - Loss on impairments and divestitures, net - 67 - - - Other - - - - - Segment Certain Items - 66 - 1 - Adjusted EBDA for Products Pipelines 1,072 1,099 1,164 1,158 1,206 Capital expenditures (GAAP)(c) - (221) (210) (242) (160) Acquisitions - - - - - Products Pipelines FCF 1,072$ 878$ 954$ 916$ 1,046$ 32 Reconciliations of Terminals FCF and Products Pipelines FCF $ in Millions a) Includes revenues, earnings from equity investments, operating expenses, other (income) expense, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Amounts are adjusted to reflect categorization of basis difference amortization (amortization of excess cost of equity investments) consistent with 2025 Segment EBDA accounting change. b) See “Non-GAAP Financial Measures—Certain Items.” c) Includes sustaining and expansion capital expenditures.
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Reconciliation of CO 2 EOR & Transport FCF 2022 2023 2024 2025 2026B EBDA for CO2 EOR & Transport(a) 798$ 658$ 640$ 569$ 490$ Certain items(b) Risk management activities (11) 4 2 (4) - Loss (gain) on impairments, divestitures and other write-downs, net - - (40) - - Segment Certain Items (11) 4 (38) (4) - Adjusted EBDA for CO2 EOR & Transport 787 662 602 565 490 Capital expenditures (GAAP)(c) (275) (255) (280) (274) (227) Acquisitions - (13) (64) - - CO2 EOR & Transport FCF 512$ 394$ 258$ 291$ 263$ 33 Reconciliations of CO2 EOR & Transport FCF $ in Millions a) Includes revenues, earnings from equity investments, operating expenses, other (income) expense, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Amounts are adjusted to reflect categorization of basis difference amortization (amortization of excess cost of equity investments) consistent with 2025 Segment EBDA accounting change. b) See “Non-GAAP Financial Measures—Certain Items.” c) Includes sustaining and expansion capital expenditures.
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Reconciliation of Adjusted EBITDA, Normalized for Divestitures 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026B Net income attributable to KMI 183$ 1,609$ 2,190$ 119$ 1,784$ 2,548$ 2,391$ 2,613$ 3,056$ 3,066$ NCI associated with Certain Items(a) - - - - - - - - - - KML noncontrolling interests(b) 28 58 33 - - - - - - - Certain Items(a) Fair value amortization (53) (34) (29) (21) (19) (15) - - - - Legal, environmental and other reserves (37) 12 46 26 160 51 - - - - Risk management activities 40 80 (24) (5) 19 57 (126) 72 (29) - Loss on impairment/Gain on divestitures 170 317 (280) 1,927 1,535 - 67 (69) (123) - Estimated gain on miscellaneous land sale - - - - - - - - - (29) Impact of 2017 Tax Cuts and Jobs Act 219 (36) - - - - - - - - Income tax Certain Items 1,085 (58) 299 (107) (491) (37) 33 (52) (2) 6 Noncontrolling interests - 240 (4) - - - - - - - Other 21 (20) (37) 72 16 32 45 7 (3) - Total Certain Items 1,445 501 (29) 1,892 1,220 88 19 (42) (157) (23) DD&A 2,261 2,297 2,411 2,164 2,135 2,186 2,250 2,354 2,453 2,536 Income tax expense(b) 853 645 627 588 860 747 682 739 834 895 Interest, net(b) 1,871 1,891 1,816 1,610 1,518 1,524 1,804 1,849 1,788 1,734 Amounts associated with joint ventures Unconsolidated JV DD&A(c) 459 507 494 547 390 398 389 409 391 370 Remove consolidated JV partners' DD&A (16) (22) (19) (40) (44) (50) (63) (62) (63) (63) Unconsolidated JV income tax expense(b) 114 82 95 82 83 75 89 78 89 83 Adjusted EBITDA 7,198$ 7,568$ 7,618$ 6,962$ 7,946$ 7,516$ 7,561$ 7,938$ 8,391$ 8,598$ Divested adjusted EBITDA(b) (683) (667) (520) (159) (126) (153) (73) (43) (33) - As normalized for divestitures 6,515$ 6,901$ 7,098$ 6,803$ 7,820$ 7,363$ 7,488$ 7,895$ 8,358$ 8,598$ 34 Reconciliation of Adjusted EBITDA, Normalized for Divestitures $ in Millions a) See “Non-GAAP Financial Measures—Certain Items.” b) To avoid duplication, amounts are adjusted to exclude amounts which are already included within “Certain Items” above. c) Includes amortization of basis differences related to our JVs.
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35 Reconciliation of Net Debt $ in Millions Reconciliation of Net Debt 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026B Current portion of debt 2,828$ 3,388$ 2,377$ 2,558$ 2,646$ 3,385$ 4,049$ 2,009$ 1,226$ 1,337$ Total long-term debt 35,015 33,936 31,915 32,131 30,674 28,403 28,067 29,881 30,777 30,984 Debt fair value adjustments (927) (731) (1,032) (1,293) (902) (115) (187) (102) (180) Preferred interest in general partner of KMP (100) (100) - - - - - - - - Foreign exchange impact on hedges for Euro Debt outstanding (143) (76) (44) (170) (64) 8 (9) 25 (44) Less: cash & cash equivalents (264) (3,280) (185) (1,184) (1,140) (745) (83) (88) (63) - Net Debt 36,409$ 33,137$ 33,031$ 32,042$ 31,214$ 30,936$ 31,837$ 31,725$ 31,716$ 32,322$ Adjusted EBITDA 7,198$ 7,568$ 7,618$ 6,962$ 7,946$ 7,516$ 7,561$ 7,938$ 8,391$ 8,598$ Net Debt to Adjusted EBITDA 5.1x 4.4x 4.3x 4.6x 3.9x 4.1x 4.2x 4.0x 3.8x 3.8x