#1INVESTOR PRESENTATION 4Q 2023 TransColorado Pipeline compressor station, Mancos, Colorado KINDER MORGAN#2Disclosure KINDER MORGAN Forward-looking statements / non-GAAP financial measures / industry & market data 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 through the Securities and Exchange Commission's ("SEC") EDGAR system at www.sec.gov and on our website at www.kindermorgan.com. Policies and Procedures - This presentation includes descriptions of our vision, mission and values and various policies, standards, procedures, processes, systems, programs, initiatives, assessments, technologies, practices, and similar measures related to our operations and compliance systems ("Policies and Procedures"). References to Policies and Procedures in this presentation do not represent guarantees or promises about their efficacy, or any assurance that such measures will apply in every case, as there may be exigent circumstances, factors, or considerations that may cause implementation of other measures or exceptions in specific instances. 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 ("Exchange Act"). 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," "strategy," "outlook," "continue," "estimate," "expect," "may," "will," "shall," and "long-term". In particular, statements, express or implied, concerning future actions, conditions or events, including the anticipated timing and benefits to our business and stockholders of the proposed acquisition of STX Midstream (including the parties ability to, including the parties' ability to obtain Hart-Scott-Rodino clearance and satisfy other conditions to closing), our Policies and Procedures and their efficacy, long term demand for our assets and services, energy- transition related opportunities, including opportunities related to alternative energy sources, future operating results or the ability to generate revenues, income or cash flow or to pay dividends 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, 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; the timing and ability to recognize the expected commercial synergies and other benefits of the proposed STX Midstream transaction; commodity prices; the timing and extent of changes in the supply of and demand for the products we transport and handle; national, international, regional and local economic, competitive, political and regulatory conditions and developments; the timing and success of business development efforts; the timing, cost, and success of expansion projects; 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; 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 timing of any review of the proposed STX Midstream transaction under Hart-Scott-Rodino and the risks and uncertainties described in this presentation and in our Annual Report on Form 10-K for the year ended December 31, 2022, 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 and other information included in this presentation have 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 and 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#3$1.815bn Acquisition of NEP's South Texas Natural Gas Pipelines 462 miles of primarily long-haul natural gas pipelines with 4.9 bcfd of transport capacity KMI to acquire NEP's South Texas assets, STX Midstream ~8.6x 2024 EBITDA; 7.0-7.5x long-term including commercial synergies (a) Immediately accretive to DCF/sh and strongly free cash flow positive Increases Net Debt-to-EBITDA by ~0.1x(b) Anticipate closing in Q1 2024; requires HSR clearance Intrastate assets complementary to KMI's existing South TX footprint - Supports strategy to serve growing LNG, industrial, Mexican export, and power generation demand markets on the U.S. Gulf Coast Integrates with our existing intrastate/interstate footprint • Connections with multiple KMI assets including TX Intrastates, TGP and NGPL Extends our direct connectivity in the lean area of the Eagle Ford basin 。 Opportunity to blend with supply from other KM assets to offer low-nitrogen natural gas desirable for LNG Commercial synergies with existing and potential projects Stable fee-based infrastructure Fixed fee business; ~75% take-or-pay - Eagle Ford Shale Freer Sinton KINDER MORGAN Corpus Christi LNG Agua Dulce Agua Dulce Hub KM Pipelines TX Intrastates Freeport LNG TGP NGPL Mier-Monterrey STX Pipelines NET Mexico Eagle Ford Midstream Dos Caminos Rio Grande LNG Texas LNG Other pipelines STX natural gas pipeline assets: - NET Mexico (90% interest, operator); 120 miles, 2.2 bcfd capacity; connects Agua Dulce hub to U.S./MX border Eagle Ford Midstream ("EFM") (100% interest); 158 miles, 1.1 bcfd capacity; connects Eagle Ford to Agua Dulce hub Dos Caminos (50% interest); 75 miles, 1.2 bcfd capacity; delivers gas from Eagle Ford producers into EFM and TX Intrastates - Average contract term >8 years; favorable renewal outlook Primarily supported by investment grade, direct end-use demand customers including Pemex, electric generation, and LDCs a) Based on KMI's financial projections. b) With full-year EBITDA contribution from acquired assets. Based on longer-term funding plans, expect transaction to be neutral to KMI's balance sheet. - 5 other assets (100% interest); 109 miles, 0.5 bcfd capacity; principally supplying demand-pull customers like power plants and LDCs 3#4Leader in North American Energy Infrastructure KINDER MORGAN Energy infrastructure, especially natural gas pipelines & storage, has a decades-long time horizon moving and storing the energy of today and tomorrow Largest natural gas transmission network Delivering energy to improve lives & create a better world ~70,000 miles of natural gas pipelines move -40% of U.S. natural gas production Have interest in 700 bcf of working storage capacity, ~15% of U.S. natural gas storage Pacific Largest independent transporter of refined products Transport ~1.7 mmbbld (a) of refined products to West and East Coast demand markets ~10,000 miles of refined products and crude pipelines KM Midstream Double H WIC CIG CP NGPL Northern Largest independent terminal operator TCGT Calnev 140 terminals & 16 Jones Act vessels Mojave Significant provider of refined products storage along the Houston Ship Channel, near the world's most complex refining center EPNG Cortez Largest CO2 transport capacity of ~1.5 bcfd ~1,500 miles of CO2 pipelines Produce CO2 and transport to the Permian where it is used for enhanced oil recovery Growing Energy Transition Portfolio Up to 6.4 bcf(a) of RNG production capacity by mid-2024 Business Mix ■ Natural gas 62% ■ Products ■ Terminals 15% 12% ■ CO2 11% KM Midstream FEP TGP Utopia TGP NGPL PPL Elba Express SNG ELC Pacific MEP Sierrita Wink KM Midstream KMLP GLNG FGT PHP GCX Cypress KMCC/ Double Eagle Storage ◆ Processing LNG facilities Note: Volumes per 2023 budget. Business mix based on 2023 budgeted Adjusted Segment EBDA. See Non-GAAP Financial Measures & Reconciliations. a) Annual capacity at KM share. ▲ Terminals ▲ Terminals 16 Jones Act tanker CEPL CO2 source fields Oil fields + RNG plants RNG plants under development ◆ Landfill gas-to-electricity facilities LNG production & fueling facilities ◆ Operational medium BTU plants Stagecoach 4#5Strategy Maximizing shareholder value. KINDER MORGAN flexibility Stable, fee-based assets Invest in a lower carbon future Financial Core energy infrastructure Safe & efficient operator Multi-year contracts ~93% take-or-pay, hedged, & fee- based cash flows (a) Established Energy Transition Ventures Group in 2021 $3.8 billion backlog with 84% allocated to lower carbon investments Investing in natural gas, RNG, liquid biofuels, and CCS infrastructure at attractive returns 4.0x 2023B expected YE Net Debt / Adjusted EBITDA Long-term target remains around 4.5x Low cost of capital Mid-BBB credit ratings Ample liquidity Disciplined capital allocation Conservative assumptions High return thresholds Self-funding capex & dividends Reduced net debt by >$11 billion since 1Q 2015 Enhance shareholder value Maintain strong balance sheet Attractive investments 2023B dividend growth; +2% YoY Share repurchases; $472mm YTD Note: Adjusted Segment EBDA and Net Debt/Adjusted EBITDA are non-GAAP measures. See Non-GAAP Financial Measures & Reconciliations. a) Based on 2023 budgeted Adjusted Segment EBDA. K Natural gas storage wellhead, Houston, Texas LO 5#6Core Holding in Any Portfolio Generating significant cash flow & returning value to shareholders > $65 billion. enterprise value ~13% owned by Largest energy infrastructure company in the S&P500 KINDER MORGAN >45% of market cap value returned to shareholders since 2016 S&P500 CURRENT DIVIDEND YIELDS y-axis represents # of S&P500 tickers within the dividend yield range specified on the x-axis management & board Highly-aligned management with significant equity interests 180 160 140 ~$200mm increase year-over-year 120 100 $7.7 billion 2023 budget Adj. EBITDA ~6.9% current dividend yield $3 billion share buyback program Budgeted 2% dividend increase in 2023. Dividend yield is top 5% in the S&P500 $472mm of share repurchases YTD. ~$1.6 billion of remaining capacity 80 60 60 64 40 20 20 At ~6.9%, KMI'S dividend yield is in the top 5% of the S&P500 0-1% 1-2% 2-3% 3-4% 4-5% 5-6% >6% Note: Adjusted EBITDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Data based on current dividend and share price from Bloomberg for companies included in the S&P500 as of 10/27/2023. 6#7Highly-Contracted Cash Flows Stable cash flows with ~67% take-or-pay or hedged earnings CONTRACT MIX OF 2023B ADJUSTED SEGMENT EBDA Take-or-pay 61% Entitled to payment regardless of throughput Reservation fee for capacity Nat gas interstates / LNG 40% Nat gas intrastates 9% Terminals 6% Jones Act 2% Crude pipes 2% Refined products pipes, 1% CO2 & transport 1% Note: Adjusted Segment EBDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Fee-based 26% KINDER MORGAN Fixed fee collected regardless of commodity price Volumetric-based revenues G&P 7% Terminals 4% Crude pipes, CO2 & Refined products pipes 9% Nat gas interstates / LNG 3% Nat gas intra. trans. Other 7% 2% 1% Hedged 6% Commodity-price based EOR, CO2 & trans., ETV, G&P, ref. prod. pipes 7% EOR oil & gas 5% G&P 1% Disciplined approach to managing price volatility Substantially hedged near-term price exposure 7#8Proven History of Cash Flow Generation and Shareholder Returns KINDER MORGAN $0.7 $0.5 $6.5 $6.7 ADJUSTED EBITDA ($ billion) +18% $0.5 $0.4 $7.1 $7.2 $6.9 $7.9 NET DEBT/ADJ. EBITDA -23% $7.7 $7.5 5.3x 5.1x 4.6x 4.5x 4.3x 3.9x DIVIDENDS PAID & SHARES REPURCHASED(a) ($ billion) $17.3 billion returned to shareholders 4.1x 4.0x $0.2 $1.3 $1.3 $0.4 $2.4 $2.4 $2.5 $2.5 $0.3 $2.2 $1.8 2016 2017 2018 2019 2020 2021 2022 2023B ■ EBITDA generated from assets divested 2016-2022 Note: Adjusted EBITDA and Net Debt are non-GAAP measures. See Non-GAAP Financial Measures & Reconciliations. a) No share repurchases assumed in 2023 budget. 2016, 2017, and 2018 include dividends paid to preferred shareholders. 2016 2017 2018 2019 2020 2021 2022 2023B 2016 2017 2018 2019 ■Dividends paid 2020 2021 2022 2023B ■Shares repurchased 8#9$3.8bn Committed Growth Capital Project Backlog as of 9/30/2023 Expect 27% of backlog capital in service in 4Q 2023, 39% in 2024, 27% in 2025, and 7% beyond KINDER MORGAN $ million TOTAL LOWER CARBON Natural Gas (excluding G&P) $2,157 $2,157 79% for end-use, 19% supply-push, 2% CCS Products (excluding G&P) 47 16 Terminals 147 129 Renewable diesel projects Renewable feedstocks & VRU emission reduction projects Energy Transition Ventures 315 315 98% RNG facilities; 2% CCS project Subtotal $2,667 $2,617 Contracted, stable cash flows, minimal direct commodity exposure EBITDA build multiple ~4.7x ~4.7x Gathering & processing $621 $575 Volume-based cash flows; 93% natural gas, 7% crude oil EOR 526 Commodity price & volume-based cash flows Total backlog $3,814 $3,193 Lower carbon investments ~84% of backlog Expect annual growth capital spend of $1-2 billion going forward, higher end of range in the near-term Note: The EBITDA build multiple reflects KM share of estimated capital divided by estimated Project EBITDA (a non-GAAP measure). See Non-GAAP Financial Measures & Reconciliations. Figures may not sum due to rounding. Lower carbon includes investments in conventional natural gas, renewable diesel, biofuel feedstocks, VRU conversions, RNG, and CCS. 6#102023 Budget KINDER MORGAN Performance driven by strong market fundamentals and robust demand growth for our existing & expanded services Key metrics Net income 2023 Budget Variance to 2022 $2.5 billion -1% Adjusted EBITDA $7.7 billion +2% Distributable Cash Flow $4.8 billion -3% (DCF) Discretionary capital(a) $2.1 billion +$0.4 billion Dividend/share Year-end Net Debt / Adj. EBITDA (b) $1.13 4.0x +2% Note: Adjusted EBITDA, Distributable Cash Flow (DCF), and Net Debt/Adjusted EBITDA are non-GAAP measures. See Non-GAAP Financial Measures & Reconciliations. a) Includes growth capital & JV contributions for expansion capital & net of partner contributions for our consolidated JVs. b) No share repurchases assumed in 2023 budget. ~$770 million capacity available for attractive investments, including share repurchases, for each 0.1x turn below ~4.5x leverage target 10#11Growing Demand for Our Natural Gas Transportation & Storage Assets Leading to Increased Value Natural Gas Transport KM NATURAL GAS TRANSPORT & SALES VOLUMES KINDER MORGAN tbtud 39.2 39.8 41.0 41.5 35.3 30.8 30.4 31.4 U.S. natural gas demand grew 36% over the past 7 years, from 78 to 106 bcfd Favorable recontracting & new opportunities Able to increase rates and/or term for transport, resulting in reduced recontracting risk; the base business can be sustained and modestly grow, for example: - - 2015 2016 2017 2018 2019 2020 2021 2022 KM pipeline throughput increased 11 bcfd since 2015 Added capacity, but many long-haul systems are highly utilized on average & have constraints on peak days, for example: average contract term TX Intrastates 2015 3.5 yrs 2022 5.7 yrs average utilization 2015 2022 TGP 86% 97% EPNG 67% 86% Difficult to build long-haul interstate pipeline capacity Natural Gas Storage Capacity nationwide has increased only 1% since 2015, KM +3% excluding acquisition/divestitures Demand volatility has increased Previously weather-driven, but now weather + renewables + LNG Example during winter storm Elliot (December 2022): Peak 1-day demand = 162 bcf (record) - Supply 86 bcf (declined due to well freeze-offs) Additional volumes lead to growth opportunities, which are tending to be concentrated along the Gulf Coast in Texas and Louisiana. Growth investment attributable to $2.7bn stable, contracted, fee-based natural gas backlog Increased storage values across our systems - As renewable penetration increases, the high level of cyclic demand further drives value for the unique storage services we can provide to customers as a reliable backstop Storage is critical to LNG facilities – demand variability due to weather, maintenance, cargo cancellations Able to increase rates and/or term for storage Rates still below cost to develop greenfield storage Source for U.S. demand figures Wood Mackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. U.S. working storage capacity per the EIA. Note: U.S. storage capacity data is only available through year-end 2021. 11#1217 14 10 9 4 2022 Provide High-Value Natural Gas Takeaway in all Major Basins U.S. production expected to grow 22% by 2030 U.S. NATURAL GAS PRODUCTION RELEVANT TO OUR FOOTPRINT bcfd 35 2023 2024 2025 2026 2027 2028 2029 2030 41 Northeast +6 bcfd KINDER MORGAN TGP provides valuable egress for NE producers & serves important domestic markets as well as LNG and Mexico Bakken Midstream Powder River Green River WIC Denver NGPL Uinta-Piceance CIG CP TCGT 26 Permian +9 bcfd 24 Haynesville +10 bcfd Mojave EPNG San Juan Permian Sierrita Horizon Utica Stagecoach KMIP Utopia LNG Terminals ◇ Processing/Treatment Plant Marcellus Gas Storage Production Basin TGP Midstream Anadarko Arkoma Haynesville Midstream Elba Express SNG /KMLP GLNG FGT PHP 10 Rockies, stable GCX Eagle Ford Cypress 8 5 Mid-Continent, -1 bcfd Eagle Ford +1 bcfd fully contracted Permian, ~0.6 bcfd PHP expansion, and evaluating additional opportunities Source: Wood Mackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Note: Rockies predominately includes production from the Niobrara, Powder River, Bakken, Three Forks formations. ELC SNG's Haynesville takeaway fully contracted Kinderhawk gathering system - additional growth through efficient capital expansions 12#13Strong Gulf Coast Footprint Positioned to Serve Demand Growth >95% of demand growth is expected to occur in Texas & Louisiana, driven by exports & industrial U.S. NATURAL GAS DEMAND bcfd KINDER MORGAN 106 LNG exports 11 LNG plant fuel 1 Industrial 32 Net Mexican exports 6 Residential & Commercial 23 129 LNG exports 26 LNG plant fuel 2 Industrial 35 Net Mexican exports 9 Residential & Commercial 23 Power 33 Power 30 2022 2030 Midstream WIC NGPL CIG CP TCGT Mojave EPNG Sierrita Midstream FEP MEP Midstream Horizon Stagecoach LNG Terminals KMIP Utopia ◇ Processing/Treatment Plant Gas Storage SNG TGP Elba Express KMLP GLNG FGT Contracted to transport PHP ~4 bcfd to Mexico GCX Cypress ELC Elba LNG export Intrastates system directly connects to petchem & industrial facilities all along the TX Gulf Coast Contracted ~7 bcfd today across 5 pipes to LNG export facilities & evaluating additional opportunities Source: WoodMackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Industrial sector includes Wood Mackenzie's "Other" category, comprised of lease and plant fuel. LNG plant fuel is assumed to be equal to 9% of LNG export volume. This volume would otherwise be included in the Industrial category. Numbers may not sum due to rounding. 2030 demand includes 3 bcfd attributable to Transport and Blue Hydrogen sectors. 13#14Transporter of Choice for LNG Facilities due to Supply Diversity, Network Connectivity, & 700 bcf of Total Working Gas Storage U.S. LNG FEEDGAS & KM TRANSPORT POTENTIAL bcfd U.S. LNG Feedgas KM transport KINDER MORGAN MEP Intrastate Louisiana Mississippi TGP contracted to move ~7 bcfd to facilities today & ~10 bcfd by the end of 2025 evaluating ~13 bcfd of additional opportunities NGPL SNG KMLP Texas Lake Charles TGP 29 Driftwood Cameron PHP Katy NGPL Henry Plaquemines 27 Port Arthur Calcasieu Pass Sabine Pass Golden Pass 24 21 TGP Freeport 20 KM Contracted LNG Export Terminals Other Proposed/Existing LNG Export Terminals Elba Liquefaction Project Market Hub 16 14 MPC GCX Corpus Christi California Agua Dulce MPO Elba Express 13 12 10 10 10 10 10 10 EPN South Carolina 7 7 7 Rio Grande 2022 2023 2024 2025 2026 2027 2028 2029 2030 Source: Wood Mackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Note: WoodMackenzie exports are multiplied by 1.09 for an estimated feedgas figure. Costa Azul LNG Baja California Georgia ELC 14#15Extensive Storage Capabilities & Premium Service Offerings Provide Valuable Solutions for Variable Demand from Utilities & Exports Largest storage position in U.S. with 700 bcf of storage ~25% subject to market-based rates; ~4.5-year average contract duration Multi-turn storage facilities provide customers with flexibility Key to supporting daily & seasonal variability from LDCs & power, LNG facilities, Mexico, and intermittent renewables For power grids with a higher mix of renewables, we offer premium services that help support volatile demand swings Pipe, storage & compression provide for hourly peak demand & duration Pressure guarantees, no-notice takes Economic & physical incentives for adequate contracting / nominations Non-ratable services are priced higher than ratable service, reflecting associated infrastructure use CIG fully contracted for LDC & power demand along the Colorado Front Range highly utilized & fully contracted EPNG serves CA & AZ power demand Midstream WIC NGPL CIG CP TCGT Mojave EPNG Sierrita highly responsive Intrastate storage critical to serving human needs during extreme weather events storage supports daily & seasonal variability in exports to Mexico, where minimal storage exists Midstream FEP MEP Midstream KINDER MORGAN Stagecoach provides flexibility to serve NE Horizon power demand Stagecoach KMIP Utopia TGP Elba Express ELC SNG TGP provides significant seasonal and peak day deliveries to NE markets FGT & SNG fully contracted with significant LDC & KMLP GLNG FGT power demand PHP GCX Cypress LNG Terminals Processing/Treatment Plant Gas Storage storage is key for LNG facilities which face interruptions from cargo scheduling changes, maintenance, & weather 15#16Serving the Permian's Growing Gas Takeaway Needs EPNG: 3 bcfd NGPL: 375 mmcfd Permian KINDER MORGAN Oklahoma NGPL Intrastates Arkansa Louis Cypress Own interest in >7 bcfd of existing Permian takeaway capacity Highly utilized capacity with long-term contracts Advantaged Intrastates network, downstream of GCX and PHP, provides shippers with end-market optionality (Houston power & petchem, LNG exports, Mexico exports) Expanding recently-built PHP by 550 mmcfd Capital-efficient project primarily adding compression Provides speed to market, with December 2023 in-service date EPNG Texas PHP: 2 bcfd + 0.6 bcfd expansion Expect Permian +9 bcfd by 2030(a) GCX: 2 bcfd 8.3 bcfd KM Intrastates system: a) Compared to 2022. WoodMackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Evaluating additional Permian transport opportunities 16#17Products Segment Overview KINDER MORGAN Refined products pipes deliver transportation fuels from refining centers to key demand markets; crude assets in major basins PRODUCTS SEGMENT Oregon Line North Line Calnev West Line San Diego Line Double H pipeline East Line Hiland Crude Products (SE) pipeline Refined Products Pipelines. Camino Real Gathering A Refined Products Terminals KM Condensate Processing Facility (Splitter) Central Florida pipeline * Transmix Facilities Double Eagle pipeline KM Crude & Condensate pipeline Crude Pipelines Crude Terminals Condensate Splitter Note: Adjusted Segment EBDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Refined Products (mbbld) Crude G&P and transport (mbbld) Adjusted Segment EBDA ($mm) 2000 1800 1600 1400 1200 1000 800 600 400 200 $1,400 $1,200 $1,000 COVID $800 $600 $400 $200 $- 2016 2017 2018 2019 2020 2021 2022 2023B long-term steady volumes & cash flow Renewable diesel projects help maintain west coast diesel market share on pipelines and enable expanded rack blending opportunities at the terminals FERC rate escalator on refined products pipes helps protect rates relative to cost inflation 17#18Products Segment's West Coast Renewable Fuels Projects KINDER MORGAN Recently announced commercial in-service of our Southern and Northern California renewable diesel hubs Subsidies & state goals for emissions reductions are driving increased RD volumes Particularly in California where stacked subsidies currently average -$4.00/gal (RIN+LCFS+BTC) Expanding our renewable fuel handling capabilities: Project - Northern CA RD by pipeline Bradshaw (Sacramento) San Jose Fresno Carson RD (Port of LA) Southern CA RD blending Colton (inland) Mission Valley (San Diego) Richmond RD (Bay area) Project Description Providing 6 mbbld R99 capacity at truck rack Providing 5 mbbld R99 capacity at truck rack Providing 10 mbbld R99 capacity at truck rack Converting ~500 mbbls storage capacity to RD Providing 15 mbbld R99 capacity at truck rack Increasing blend capabilities to 20% Providing 15 mbbld blended diesel capacity at truck rack Providing 5 mbbld R99 capacity at truck rack Converting ~60 mbbls storage capacity to RD Providing 15 mbbld blended diesel capacity at truck rack Chico Bradshaw Oakland North Line San Jose Investing ~$75 million to supply California with lower emissions fuel Nevada California Calnev Los Angeles Colton San Diego West Line Indio Line San Diego Potential for additional expansion opportunities, including RD feedstock logistics Legend Products Pipelines Refined Product Terminals Proposed Renewable Diesel Sites Transmix Facilities Cities/Towns Arizona New Mexico East Line 18#19Terminals Segment Overview KINDER MORGAN Refined products focused; providing customers with unmatched scale, service-offerings & market-making connectivity # of capacity ASSET SUMMARY terminals (mmbbls) Terminals segment - Bulk 28 Terminals segment - Liquids 47 Products segment 65 Total Terminals 140 56 134 660 78 Jones Act: 16 tankers TERMINALS SEGMENT VOLUMES & UTILIZATION Percent of liquids capacity leased 20 15 10 5 Bulk tonnage (mm tons) 100% 80% Terminals 60% KM Terminals-Liquids KM Products Pipelines KM Terminals - Bulk 40% Jones Act Tankers 20% -% 2019 2020 2021 2022 2023B 19#20Industry-Leading Renewable Feedstock Storage & Logistics Offering Expanding Lower Mississippi River Hub Modifying 30 tanks & enhancing rail, truck, and marine capabilities for Neste at Harvey KINDER MORGAN New heated storage capacity and various marine, rail, & pipeline infrastructure improvements at GRT $80 million capex 2Q 2023 in service 657 mbbl capacity can expand further $55 million capex 4Q 2024 operational 247 mbbl capacity - Our flexible terminaling network improves efficiency & sustainability of NESTE supply chain Network scale can keep pace with NESTE's RD feedstock growth Handle other renewable volumes for NESTE including: Feedstock in Midwest & Northeast SAF at Galena Park Constructing a new steam-traced and insulated outbound pipeline connection to nearby RD plant KM's Geismar River Terminal is strategically positioned to meet the growing feedstock requirement of the plant Supported by a long-term commercial commitment Leveraging existing assets towards capital-efficient, attractive return opportunities supporting growing renewable fuels market 20#21CO2 Segment Overview World class, fully-integrated assets | CO2 source to crude oil production & takeaway in the Permian Basin Interest in 5 oil fields with 9.3 billion barrels of Original Oil In Place Interest in 3 CO₂ fields with 37 tcf of Original Gas In Place Doe Canyon KINDER MORGAN $777 Colorado CO2 pipelines CO2 source fields ☑Oil fields CO2 EOR & TRANSPORT FREE CASH FLOW $ millions ■FCF □ Capex Adj. Segment EBDA $789 McElmo Dome $746 Crude pipelines $707 $652 Permian basin $185 $275 $242 $349 $186 Cortez New Mexico Bravo Dome $561 $514 $535 $466 $358 Katz 2019 2020 2021 2022 2023B Denver City SACROC Tall Cotton $ per net barrel Snyder Midland ~1,500 miles of CO2 $80 SIZEABLE MARGIN ON OIL PRODUCTION Cash costs ◆ Avg. realized oil price $66.78 $64.19 El Paso Wink Goldsmith $53.78 $52.71 pipelines with $60 $49.49 Yates McCamey capacity to move up to 1.5 bcfd Texas Iraan $40 cash costs $25/bbl $20 $- 2019 2020 2021 2022 2023B Note: CO₂ EOR & Transport FCF and Adjusted Segment EBDA are non-GAAP measures. See non-GAAP Financial Measures & Reconciliations. Cash costs & revenue per net oil barrel, including hedges where applicable. Cash costs exclude DD&A expense and primarily consist of expenses related to power, labor, rig work, CO2 purchases, taxes other than income tax, and gas processing. Lower cash costs in 2021 were driven by a benefit from returning power to the grid. 21#22Growing RNG Portfolio LANDFILL-RNG ANNUAL PRODUCTION CAPACITY net to KM 4.9 bcf operational (5.4 bcf gross) KINDER MORGAN PRIMARILY CONTRACTED IN GROWTH PLAN TRANSPORTATION MARKET TODAY Potential to grow +0.6 bcf over next decade Long-term contracts in transportation/RIN with little capex market +0.8 bcf expected online 2023 +0.7 bcf expected online mid-2024 =6.4 bcf (6.9 bcf gross) Focused on bringing existing facilities online Short term contracted into RINS market, opportunity for fixed-price contracts will grow as voluntary market develops Expect first full-year Project EBITDA multiple of ~6x based on cumulative investment once all facilities are in service 6.9 bcf of RNG reduces emissions by 3.9 million metric tons CO2 e per year, equivalent to: 9.1mm barrels of oil consumed R 439mm gallons of gasoline consumed carbon sequestered by 4.6mm acres of U.S. forest Note: Project EBITDA is a non-GAAP measure. See Non-GAAP Financial Measures and Reconciliations. Emission calculation and equivalencies based on the EPA's Landfill Gas Energy Benefits Calculator. We expect our plants to capture 14.8 bcf/year of feedgas to produce 6.9 bcf/year of RNG. 22#23KINDER MORGAN Red Cedar Carbon Capture and Sequestration Project Utilizing KM's assets and expertise to enable an accretive CCS project Overview Red Cedar Gathering (RCG) is a natural gas midstream joint-venture between Southern Ute Indian Tribe Growth Fund (51%) and Kinder Morgan (49%) in southern Colorado A term sheet has been executed and definitive agreements are being finalized between RCG and Kinder Morgan ETV to transport and permanently sequester CO2 Scope - RCG will install carbon capture equipment at two natural gas treating facilities with the ability to capture up to 400,000 metric tons per year of CO2 and deliver the captured CO2 to Kinder Morgan's existing Cortez pipeline Kinder Morgan will be responsible for transporting the CO2 to an existing Kinder Morgan Class II well in the Permian Basin and permanently sequestering the CO2 Project Details MRV plan has been approved by the EPA and permit modifications have been submitted to Texas Railroad Commission El Paso Colorado Red Cedar Facilities New Mexico Cortez CO2 pipelines × Oil fields Denver City SACROC Tall Cotton Snyder Midland Goldsmith Katz - Net capital investment of less than $50 million Yates McCamey Texas Iraan Project returns competitive with traditional business Target in-service by Q4 2024 Ownership in RCG JV, existing CO₂ pipeline network, and downhole experience allow KM to participate in the entire CCS project value chain 23#24ESG Recognition Highly rated by multiple agencies KINDER MORGAN FTSE #3 of Oil & Gas Pipelines subsector MSCI A Oil & Gas Refining, Marketing, Transportation & Storage Industry Sustainalytics #3 of 117 Oil & Gas Storage & Transportation & #4 of 203 Refiners & Pipelines Refinitiv #7 of 232 Oil & Gas Related Equipment and Services Companies SSGA top 10% R-Factor in Oil & Gas Midstream sector Moody's overall ESG score 18% higher than sector average Included in several ESG indices FTSE4Good, S&P 500 ESG, JUST Capital Note: Sustainalytics ESG risk ranking, MSCI ESG rating, FTSE ESG rating rank, Refinitiv ESG score rank, Moody's Vigeo Eiris ESG score, and SSGA R-Factor as of October 2023. 24#25Compelling Investment Opportunity Strategically-positioned assets generating substantial cash flow with attractive investment opportunities Pacific Northern NATURAL GAS PRODUCTS TERMINALS ▲ Terminals. ▲ Terminals 16 Jones Act tanker Storage Processing LNG facilities KM Midstream Double H WIC CIG CP NGPL TCGT Calnev Mojave EPNG Cortez KM Midstream FEP MEP CO2 CO2 source fields Oil fields RNG plants RNG plants under development ◆ Landfill gas-to-electricity facilities LNG production & fueling facilities Operational medium BTU plants TGP Utopia NGPL TGP PPL Elba Express SNG ELC Pacific Sierrita Wink KM Midstream KMLP GLNG FGT PHP GCX Cypress KMCC/ Double Eagle CEPL Stagecoach KINDER MORGAN Largest energy infrastructure company in the S&P500 Stable cash flows with ~67% take-or-pay or hedged earnings(a) Strong balance sheet with flexibility Attractive returns on growth projects ~6.9% current yield & healthy dividend coverage Dividend yield in the top 5% of the S&P500 ~$1.6 billion of share repurchase program remaining Highly-aligned management with ~13% share ownership Positioned for energy future with a vast network of critical assets & lower carbon focus a) Based on Adjusted Segment EBDA (a non-GAAP measure) per 2023 budget. See Non-GAAP Financial Measures & Reconciliations. 25#26APPENDIX Terminal Pit 11, Pasadena, Texas H#2723% 30% Energy is Essential to Human & Economic Development KINDER MORGAN The transition to a renewable-energy world will not be seamless and will require the ongoing use of hydrocarbons U.S. POPULATION, GDP & ENERGY SUPPLY BY SELECT FUEL TYPES 2022, 2030, 2040, 2050 +12% +69% +138% +15% 42 44 +13% 36 35 37 6% 2040 % mix 5% 36% Population 33 27 22 20 GDP 22 13 31 27 32 Renewables Natural Gas Oil products -50% 6 12 Coal 10 -27% Other Hydrocarbons have significant advantages & are irreplaceable in certain applications: cement, steel, fertilizer, plastics These are materials that are needed for a growing population and a rising standard of living Note: U.S population in million people. U.S. GDP in trillion USD (2012). Renewables, natural gas, oil products, coal, and other in quadrillion btu. Other includes nuclear, non-biogenic municipal waste, hydrogen, methanol, and some domestic inputs to refineries. 372 361 346 333 Source: EIA 2023 Annual Energy Outlook. 27#28Energy Transitions Take Time Our assets and services will be needed for a very long time GLOBAL ENERGY MIX BY FUEL PWh KINDER MORGAN Energy transitions take a long time and consist of adding energy forms, not eliminating existing forms % of energy mix Biomass ■ Coal ■Oil 180 160 ■Natural gas Renewables Nuclear 140 Coal took 60 years to achieve a 50% share of global energy 120 Oil 60 years to achieve 40% 100 80 60 60 60 40 40 20 20 Natural gas 60 years to achieve 20% Nuclear took 80 years from discovery to widespread deployment 50% 40% 12% 23% 20% 29% 25% 28 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020 Source: Pre-1965 from Energy Transitions: Global and National Perspectives; 1965 and beyond from BP's Statistical Review of World Energy.#29Stable, Growing U.S. Production U.S. NATURAL GAS PRODUCTION bcfd 108 102 96 96 90 90 84 78 Production increases to 104 bcfd by 2025 KINDER MORGAN U.S. CRUDE PRODUCTION & REFINED PRODUCT SUPPLY mmbbld -Road fuels Crude Jet Fuel 15 12 9 6 3 Crude production continues to grow Refined product volumes remain stable 72 2018 2019 2020 2021 2022 2023 2024 2025 2018 2019 2020 2021 2022 2023 2024 2025 Left: WoodMackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Right: EIA 2023 Annual Energy Outlook (March 2023). 29#30& other areas Natural Gas Gathering & Processing Assets Across Key Basins Volume recovery ongoing G&P BUSINESS AS % OF 2023B KMI ADJUSTED SEGMENT EBDA 2% Haynesville KinderHawk assets with proximity to Gulf Coast industrial & LNG 2% Bakken gas Hiland system in core Williston acreage, including McKenzie County 1% Eagle Ford Copano South Texas & EagleHawk JV assets, primarily in LaSalle County 3% Other gas Multiple systems in Uinta, Oklahoma, San Juan NATURAL GAS SEGMENT GATHERING VOLUMES bbtud 4,000 3,000 2,000 3,474 bbtud in Q3'23 1,000 3,668 bbtud 2023B KINDER MORGAN SHORT-TERM PRODUCTION OUTLOOK dry gas, bcfd, 2019 - 2024 15 10 2024 +14% from 2021 trough 5 2024 +67% over pre-COVID levels 2024 +31% over pre-COVID levels 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 Note: Adjusted Segment EBDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Pre-COVID levels are based on 2019 production. Production outlook from Wood Mackenzie's North America Gas 10- Year Investment Horizon Outlook, October 2023. 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 1Q23 2Q23 3Q23 Eagle Ford Haynesville/CV Bakken / Three Forks 30#31Refined Products Volumes Continue to Recover DIESEL mbbld GASOLINE mbbld JET FUEL mbbld 2022 2023B 2023 2022 - 2023B 2023 2022 1,200 1,200 1,200 1,000 800 600 400 200 1,000 800 600 400 200 1,000 800 600 400 200 KINDER MORGAN 2023B 2023 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Q3'23: 1,002 mbbld 362 mbbld 292 mbbld 395 mbbld 277 mbbld 2023B: 992 mbbld 2022: 978 mbbld Impacted by refinery outages in 1H'23 367 mbbld Rebounding throughout the year Note: Kinder Morgan Refined Products volumes include SFPP, CALNEV, Central Florida & PPL (KM share). 264 mbbld Continuing to strengthen 31#32Energy Transition Ventures (ETV) Group KINDER MORGAN The group is evaluating commercial opportunities. emerging from the lower carbon energy transition Mature RNG, RD, Renewable Power Developing Carbon Capture & Sequestration Early Stage Hydrogen Established a growing RNG platform with the Kinetrex, Mas & NANR acquisitions and expanding opportunities in CCUS space ETV Group focused on opportunities outside of our existing asset base Other business segments will continue to pursue their own energy transition opportunities on existing assets Most attractive opportunities likely to be synergistic with our existing infrastructure and expertise Projects will have to compete for capital Remain disciplined and focused on attractive returns exceeding cost of capital 32#33RNG Market Opportunity U.S. RNG PRODUCTION bcfd expect landfills to drive growth 3.2 0.5 0.3 1.0 1.6 2.4 KINDER MORGAN 3.7 RNG DEMAND MARKETS transportation market RNG-based vehicles emit up to 75% less GHG emissions than diesel vehicles (a) Fleets with decarbonization goals may choose to purchase RNG Typically, prices near traditional natural gas price, like Henry Hub for example: $3.16/M M Btu HH spot price If RNG volumes are consumed by fleets in the transportation market, then RIN credits may be earned, which are then purchased by RFS-obligated parties (like refiners) in order to comply with federal requirements: $40.69/MM Btu D3 RIN value (b) voluntary market Parties interested in voluntarily decarbonizing (like LDCs, utilities, universities, industrial) are increasingly interested in RNG, despite the premium price relative to traditional natural gas 2022 2025 2030 2035 2040 2045 2050 government program incentivizes RNG production, provides margin for producer slimmer margin but fixed- price, 10+ year contracts Sources: U.S. RNG production per WoodMackenzie, WoodMackenzie, North America Gas 10-Year Investment Horizon Outlook, October 2023. Includes all forms of RNG production. a) Emissions data per the EPA. b) $3.47 2023 D3 RIN price multiplied by 11.727 to convert to $/MMBtu. Pricing as of 10/27/2023. 33#347% Commodity- price based 3% 9% 2% G&P 1% 6% 2% Contract Strategy Insulates Cash Flow Through Commodity Cycles Structure long-term contracts that minimize price & volume volatility Natural Gas 2023B Adjusted Segment EBDA: Interstate / LNG TX Intrastate 67% take or-pay or hedged Volumes & price are contractually fixed 40% 26% fee- based Price is fixed, volumes are variable Avg. remaining contract life Additional cash flow security KINDER MORGAN Primarily acreage dedications for fee-based contracts as of 1/1/2023 6.0/17.7 years Tariffs are FERC-regulated 6.2 years 4.1 years Refined products 1% 9% 1% generally not applicable Products Crude transport 2% 1% 2.3 years Pipeline tariffs are FERC-regulated ~2/3 of 2023B Products Segment Adj. Segment EBDA has an annual inflation-linked tariff escalator Crude gathering 1% Liquids terminals 5% 2% 2.7 years Terminals Jones Act tankers 2% 3.3 years ~3/4 of 2023B Terminals Segment Adj. Segment EBDA has annual price escalators (inflation linked or fixed price escalators) Bulk terminals: primarily minimum volume guarantee or requirements Bulk terminals 1% 2% 4.3 years EOR Oil & Gas 5% 2% CO2 CO2 & Transport 1% ETV 1% 6.2 years Commodity-price based contracts are mostly minimum volume committed 1% Note: Adjusted Segment EBDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Numbers may not sum due to rounding. TX Intrastate average remaining contract life includes term sale portfolio. 34#352023 Budget Sensitivities Limited overall commodity exposure 2023B assumptions Natural gas G&P volumes 3,668 bbtud Refined products volumes (gasoline, diesel & jet fuel) 1,663 mbbld for Products segment Change Potential Impact to Adjusted EBITDA & DCF (full year) Natural Gas Products Terminals +/- 5% $40 million +/- 5% $37 million $12 million Crude oil & condensate volumes (includes Bakken oil G&P) 510 mbbld net +/- 5% Crude oil & NGL production volumes 38 mbbld net +/- 5% in net volumes $85.00/bbl WTI crude oil price +/- $1/bbl WTI $5.50/Dth natural gas price +/- $0.10/Dth $15 million KINDER MORGAN CO2 Total $40 million $49 million $15 million $25 million $25 million $1.0 million $1.2 million $3.6 million $5.8 million $1.0 million (a) $1.0 million (a) NGL / crude oil price ratio +/- 1% price ratio $1.4 million 54% in Natural Gas segment & 45% in CO2 segment $2.71/RIN D3 RIN price +/- $0.10/RIN SOFR rate: 4.72% $3.5 million $4.9 million $3.8 million $3.8 million Potential Impact to DCF (balance of year) +/-10-bp change in SOFR $6.3 million (b) Note: These sensitivities are general estimates of anticipated impacts on our business segments & overall business of changes relative to our assumptions; the impact of actual changes may vary significantly depending on the affected asset, product & contract. Adjusted EBITDA and Distributable Cash Flow (DCF) are non-GAAP measures. See Non-GAAP Financial Measures & Reconciliations at the end of this presentation for additional information. a) Assumes constant ethane frac spread vs. natural gas prices. b) As of 12/31/2022, we had $7.5 billion of fixed-to-floating interest rate swaps on our long-term debt and -24% of the principal amount of our debt balance was subject to variable interest rates - either as short- or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. Taking into account SOFR locks effective on 12/30/2022 (and not included in budget), we have fixed the LIBOR component on $1.25 billion of our floating rate swaps through the end of 2023, and effectively 20% of our debt therefore subject to variable interest rates. 35#36Minimum Book Tax Detail KINDER MORGAN High-level example of calculation Net income Add back: Book depreciation Add back: Book federal income tax Subtract: Tax depreciation Adjusted Financial Statement Income (AFSI) × 15% Minimum Book Tax (MBT) Subtract: Any applicable credits MBT after credits Pay the greater: MBT or ordinary federal cash taxes Limited to 75% of MBT annually; $298 million of General Business Credits as of 12/31/22 MBT applies to companies generating average annual AFSI >$1bn over the prior 3 years Do not expect to be subject to MBT in 2023, 2024, or 2025 100% of MBT payments can be credited against future ordinary tax 36#37NON-GAAP FINANCIAL MEASURES & RECONCILIATIONS Elba liquefaction, Elba Island, Georgia ISd 600#38KINDER MORGAN 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 either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (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). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures" below). 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 from Joint Ventures" below). DCF is a significant performance measure used by us, investors and other external users of our financial statements 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 is also used by us and external users to compare the performance of companies across our industry. 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. Adjusted Segment EBDA is calculated by adjusting segment earnings before DD&A and amortization of excess cost of equity investments (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. Adjusted EBITDA is calculated by adjusting net income attributable to Kinder Morgan, Inc. before interest expense, income taxes, DD&A, and amortization of excess cost of equity investments (EBITDA) for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures" below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income attributable to Kinder Morgan, Inc. 38#39Use of Non-GAAP Financial Measures (Continued) KINDER MORGAN Amounts from 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 items (DD&A 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. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. 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 most comparable measure to Net Debt is total debt. Project EBITDA 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 from Joint Ventures," and in conjunction with capital expenditures for the project, is the basis for our Project EBITDA multiple. 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. 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. 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 Free Cash Flow is calculated by reducing Segment EBDA from our CO2 EOR & Transport assets by Certain Items, capital expenditures (sustaining and expansion) and acquisitions attributable to the EOR & Transport assets. Management uses CO2 EOR & Transport Free Cash Flow as an additional performance measure for our CO2 EOR & Transport assets. We do not provide budgeted CO2 EOR & Transport Segment EBDA (the GAAP financial measure most directly comparable to 2023 budgeted CO2 EOR & Transport 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 on derivatives marked to market. 39#40GAAP Reconciliations $ in millions Certain Items 2022 Fair value amortization $ (15) Legal, environmental and other reserves 51 Change in fair value of derivative contracts (a) 57 Income tax Certain Items (b) (37) Other 32 Total Certain Items (c,d) $ 88 Reconciliation of Segment EBDA to Adjusted Segment EBDA Natural Gas Pipelines Segment EBDA (e) 2022 Actual 2023 Reconciliation of Net Debt Budget Current portion of debt EA $ 4,801 $5,066 Total long-term debt Certain Items Debt fair value adjustments Legal, environmental and other reserves 51 Foreign exchange impact on hedges for Euro Debt outstanding Change in fair value of derivative contracts 64 Less: cash & cash equivalents Other 26 Net Debt Natural Gas Pipelines Adjusted Segment EBDA $ 4,942 5,066 Adjusted EBITDA Net Debt to Adjusted EBITDA (e) Products Pipelines Segment EBDA $ 1,107 $ 1,238 Terminals Segment EBDA (e) $ 975 $ 1,000 CO2 Segment EBDA (e) Certain Items Change in fair value of derivative contracts CO2 Adjusted Segment EBDA $ 819 $ 879 (11) $ 808 $ 879 a) Gains or losses are reflected when realized. KINDER MORGAN 2022 $ 3,385 28,403 (115) 8 (745) $30,936 $ 7,516 4.1X b) Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI's income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities. c) Amount includes $1 million included within "Earnings from equity investments" included within "Change in fair value of derivative contracts." d) Amount includes, in aggregate, $(11) million, included within "Interest, net" which consist of $(15) million of "Fair value amortization" and $4 million, of "Change in fair value of derivative contracts." e) Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other income, 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. 40#41Net Income & DCF $ in millions 2023 2022 Change Budget Actual % Net income attributable to Kinder Morgan, Inc. Certain Items Fair value amortization Legal, environmental and other reserves Change in fair value of derivative contracts Income tax Certain Items Other $ 2,525 $ 2,548 $ (23) (1%) (12) (15) 51 57 (37) 32 Total Certain Items (12) 88 (100) NM DD&A 2,197 2,186 11 1% Amortization of excess cost of equity investments 67 75 75 (8) (11%) (b) Income tax expense (a) Cash taxes Sustaining capital expenditures Amounts from joint ventures Unconsolidated JV DD&A Remove consolidated JV partners' DD&A Unconsolidated JV income tax expense (b,c) Unconsolidated JV cash taxes Unconsolidated JV sustaining capital expenditures Remove consolidated JV partners' sustaining capital expenditures Other items (d) 724 747 (23) (3%) (15) (13) (2) (15%) (857) (761) (96) (13%) 323 323 (62) (50) (12) (24%) 84 75 9 12% (81) (70) (11) (16%) (154) (148) (6) (4%) 9 8 1 13% 81 (38) 119 NM DCF $ 4,829 $ 4,970 $ (141) (3%) Weighted average shares outstanding for dividends (e) 2,263 2,271 (8) (0%) Basic and diluted earnings per share Adjusted EPS DCF per share Expected/Declared dividend per share SSSSA 1.12 $ 1.11 $ 2.13 SA SA SA $ 1.12 $ $ 1.16 $ (0.05) (4%) $ 2.19 $ (0.06) $ 1.13 $ 1.11 $ 0.02 (3%) 2% KINDER MORGAN a) To avoid duplication, 2022 adjustments for income tax expense exclude $(37) million, which amount is already included within "Certain Items." See table captioned "Certain Items" on slide 53. b) Associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments. c) Includes the tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments. The impact of KMI's income tax provision on Certain Items affecting earnings from equity investments is included within "Certain Items" above. d) Includes non-cash pension expense, non-cash compensation associated with our restricted stock program and pension contributions. e) Includes 16 million and 13 million average unvested restricted shares that participate in dividends in 2023 and 2022, respectively. 41#42Net Income & Adjusted EBITDA $ in millions 2023 Budget 2022 Change Actual $ % Net income attributable to Kinder Morgan, Inc. Certain Items Fair value amortization Legal, environmental and other reserves $ 2,525 $ 2,548 $ (23) -1% (12) (15) 51 Change in fair value of derivative contracts 57 Income tax Certain Items (37) Other 32 Total Certain Items (12) 88 (100) NM DD&A 2,197 2,186 11 1% Amortization of excess cost of equity investments 67 75 (8) (11%) Income tax expense (a) 724 747 (23) (3%) Interest, net (b) 1,855 1,524 331 22% Amounts from joint ventures Unconsolidated JV DD&A 323 323 Remove consolidated JV partners' DD&A (62) (50) (12) 24% Unconsolidated JV income tax expense (c) 84 75 9 Adjusted EBITDA $ 7,701 $ 7,516 $ 185 12% 2% KINDER MORGAN a) To avoid duplication, 2022 adjustments for income tax expense exclude $(37) million, which amount is already included within "Certain Items." See table captioned "Certain Items" on slide 53. b) To avoid duplication, 2022 adjustments for interest, net exclude $(11) million, which amount is already included within "Certain Items." See table captioned "Certain Items" on slide 53. c) Includes the tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments. The impact of KMI's income tax provision on Certain Items affecting earnings from equity investments is included within "Certain Items" above. 42#43Reconciliations of KMI FCF & CO2 Segment FCF $ in millions Reconciliation of KMI FCF CFFO Capital expenditures (a) FCF Dividends paid (b) FCF after dividends Reconciliation of CO2 EOR & Transport FCF EBDA for CO2 EOR & Transport Certain items: Loss (gain) on non-cash impairments, project write-offs and divestitures Derivatives and other Severance tax refund Adjusted EBDA for CO2 EOR & Transport Capital expenditures (a) Acquisitions CO2 EOR & Transport FCF a) Includes sustaining and expansion capital expenditures. b) 2018 includes dividends paid for the preferred shares. 2018 2019 2020 2021 2022 2,139 (1,774) $ 365 $ $ 5,043 $ 4,748 $ 4,550 $ 5,708 $ 4,967 (2,904) (2,270) (1,707) (1,281) (1,621) 2,478 2,843 4,427 3,346 (2,163) (2,362) (2,443) (2,504) 315 $ 481 $ 1,984 $ 842 $ SA 759 $ 681 $ (292) $ 752 $ 800 79 75 950 (10) 90 (49) (6) (11) (21) 907 707 652 746 789 (397) (349) (186) (185) (275) (21) - $ 489 $ 358 $ 466 $ 561 $ 514 KINDER MORGAN 43#44Reconciliation of Adjusted EBITDA, Normalized for Divestitures $ in millions Reconciliation of Adjusted EBITDA, Normalized for Divestitures Net income attributable to Kinder Morgan, Inc. Noncontrolling interest certain item KML noncontrolling interests (a) Certain Items Fair value amortization Legal, environmental and other reserves Change in fair value of derivative contracts 2016 2017 2018 2019 2020 2021 2022 $ 708 $ 183 $ 1,609 $ 2,190 $ 119 $ 1,784 $ 2,548 (8) 28 58 33 33 (143) (53) (34) (29) (21) (19) (15) (16) (37) 12 46 26 160 51 75 40 80 (24) (5) 19 57 Loss on impairment 848 170 317 (280) 1,927 1,535 Project write-offs 171 Impact of 2017 Tax Cuts and Jobs Act 219 (36) Income tax Certain Items 18 1,085 (58) 299 (107) (491) (37) Noncontrolling interests 240 (4) Other (20) 21 (20) (37) 72 16 32 Total Certain Items 933 1,445 501 (29) 1,892 1,220 88 DD&A 2,209 2,261 2,297 2,411 2,164 2,135 2,186 Amortization of excess cost of equity investments 59 61 95 83 140 78 75 Income tax expense (a) 899 853 645 627 588 860 747 Interest, net (a) 1,999 1,871 1,891 1,816 1,610 1,518 1,524 Amounts from joint ventures Unconsolidated JV DD&A Remove consolidated JV partners' DD&A Unconsolidated JV income tax expense (a) Adjusted EBITDA Divested adjusted EBITDA (a) As normalized for divestitures $ 7,242 $ 7,198 $ 7,568 $ 7,618 $ 6,962 $ 7,946 $ 7,516 (701) (534) (526) (399) (94) (56) (48) $ 6,541 $ 6,664 $ 7,042 $ 7,219 $ 6,868 $ 7,890 $ 7,468 362 398 412 411 407 312 323 (13) (16) (22) (19) (40) (44) (50) 94 114 82 95 82 83 75 a) To avoid duplication, amounts are adjusted to exclude amounts which are already included within "Certain Items" above. KINDER MORGAN 44