#1INVESTOR PRESENTATION 2Q 2023 TransColorado Pipeline compressor station, Mancos, Colorado KINDER MORGAN#2KINDER MORGAN Disclosure 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 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; 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 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#3Leader 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 3#4Strategy Maximize the value of our assets on behalf of shareholders KINDER MORGAN Stable, fee-based assets Core energy infrastructure Safe & efficient operator Multi-year contracts ~93% take-or-pay, hedged, & fee- based cash flows (a) Invest in a lower carbon future Established Energy Transition Ventures Group in 2021 $3.7 billion backlog with 86% allocated to lower carbon investments Investing in natural gas, RNG, liquid biofuels, and CCS infrastructure at attractive returns Financial flexibility 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 for last 7 years 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; $113mm 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 4#5Core Holding in Any Portfolio Generating significant cash flow & returning value to shareholders ~$70 billion. enterprise value Largest energy infrastructure company in the S&P500 ~13% owned by management & board $7.7 billion 2023 budget Adj. EBITDA ~6.5% current dividend yield $3 billion share buyback program KINDER MORGAN ~38% 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 Highly-aligned management with significant equity interests 200 180 160 ~$200mm increase year-over-year 140 120 100 Budgeted 2% dividend increase in 2023. Top 10 dividend in the S&P500 80 60 40 $113mm of share repurchases YTD. ~$1.94 billion of repurchase program remaining 20 At ~6.5%, KMI has a top 10 dividend yield in 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 4/28/2023. 5#6Highly-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 6#7Proven History of Cash Flow Generation and Shareholder Returns $ billions KINDER MORGAN ADJUSTED EBITDA +18% $0.5 $0.4 $7.9 $0.7 $0.5 $6.5 $6.7 $7.7 $38 $7.1 $7.2 $7.5 $37 $6.9 NET DEBT -19% $34 $33 $32 $31 $31 $31 DIVIDENDS PAID & SHARES REPURCHASED(a) $17.3 billion returned to shareholders $0.4 $2.4 $2.4 $2.5 $2.5 $0.3 $2.2 $0.2 $1.3 $1.3 $1.8 2016 2017 2018 2019 2020 2021 2022 2023B 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 ■Dividends paid 2020 2021 2022 2023B ■Shares repurchased 7#82023 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 8#9$3.7bn Committed Growth Capital Project Backlog as of 3/31/2023 Expect 53% of backlog capital in service in 2023, 25% in 2024, and 22% beyond KINDER MORGAN $ million Natural Gas Products TOTAL LOWER CARBON $ 2,567 $ 2,567 145 67 Terminals 257 199 56% for end-use, 16% supply-push, 27% G&P, 1% CCS Renewable diesel projects Renewable feedstocks & VRU emission reduction projects Energy Transition Ventures 372 372 98% RNG facilities; 2% CCS project Subtotal $ 3,341 $ 3,205 EBITDA build multiple ~3.5x ~3.5x CO₂ $380 EOR projects Total $ 3,721 Lower carbon investments ~86% of backlog ~ Expect annual growth capital spend of $1-2 billion going forward, compared to ~$2-3 billion historically 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. 9#10MARKET FUNDAMENTALS CIG Rawlins station, Sinclair, Wyoming " BB#11Energy 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% 372 361 346 333 +15% 44 42 338 31 +69% +138% 33 27 22 20 27 22 13 +13% 37 35 36 32 Renewables 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 Natural Gas Oil products Note: U.S population in million people. U.S. GDP in trillion USD. Renewables, natural gas, and oil products in quadrillion btu. Source: EIA 2023 Annual Energy Outlook. Population GDP 11#12Energy 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% 12 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.#13Significant Additional LNG Capacity Will Be Needed to Meet Future Demand KINDER MORGAN US & Middle East account for ~75% of LNG supply growth to 2050 2021-2050 LNG IMPORT DEMAND GROWTH bcfd GLOBAL LNG VOLUMES bcfd Southeast Asia Rest of the world 70 63 60 60 54 55 57 60 India China 50 50 Japan and Korea 44 -8 European Union -13 40 40 30 30 20 10 21 13 5 AVERAGE ANNUAL LNG SPEND $billion ■ Production ■Infrastructure ~19 bcfd of volume growth from 2021 to 2050 Requires ~25 bcfd of new capacity beyond projects currently under construction given. forecasted declines in Russia & North Africa 2016-21 $134 $86 $220 2022-30 $196 $85 $281 2031-50 $174 $82 $256 2015 2021 2025 2030 2035 2040 2045 2050 Based on IEA data from the IEA (2022) World Energy Outlook, World Energy Outlook 2022 - Analysis – IEA. All rights reserved; presentation modified by Kinder Morgan (data unchanged). STEPS (Stated Policies) scenario. Infrastructure spend includes liquefaction and regasification terminals, ships, pipelines and storage. IEA does not provide a 2025 projection. 2025 data point is an extrapolation of the straight-line IEA projection from 2021 to 2030. 13#14U.S. Expected to Support Increasing Global Demand Reliable trade partner with ample reserves & price-competitive production FULL CYCLE COST OF LNG PROJECTS ■US Other $/mmbtu 12 U.S. LNG exports are globally competitive and can provide reliable & affordable gas at a cost $8-$9/mmbtu new LNGI capacity ~100 mtpa of 10 required to meet 2035 demand 8 ~170 mtpa I needed by 2035 | in a delayed I transition I scenario I KINDER MORGAN U.S. proved natural gas reserves increased 32% in 2021 U.S. NATURAL GAS U.S. OIL 360 bbo total reserves 2,973 tcf total reserves or 86 years or 83 years of production of production 6 2 30 60 90 120 150 180 210 240 270 300 330 mtpa U.S. EXPORTS ■natural gas exports (bcfd) ■oil exports (mmbbld) 15 3 2021 26 7 2030 LNG project costs based on McKinsey Energy Insights analysis. LNG projects currently facing severe difficulties in terms of technology, sanctions, or stakeholder alignment (including Russian, Iranian and Mozambique projects) are excluded. Exports based on IEA data from the IEA (2022) World Energy Outlook, World Energy Outlook 2022 - Analysis - IEA. All rights reserved; presentation modified by Kinder Morgan (data unchanged). STEPS (Stated Policies) scenario. Total reserves based on EIA data and include proved, probable, and possible reserves. Years of remaining production calculated based on 2021 U.S. production. 14#15■ Coal U.S. CO2 Emissions Declined Since 2007 while GDP grew ~45% Primarily due to converting coal power generation to natural gas generation KINDER MORGAN U.S. ELECTRICITY GENERATION MIX % of total generation 23% 22% 18% 7 U.S. CO2 EMISSIONS FROM ENERGY CONSUMPTION billion metric tons -17%, -1.0 billion metric tons 5 7% 22% 4 40% 2 49% 20% 2007 ■Natural gas 2022 1 3 6 5.0 5.0 5.1 5.2 5.3 5.3 5.5 5.6 5.6 5.7 5.9 5.8 5.8 5.9 6.0 6.0 5.9 6.0 5.8 5.4 5.6 5.4 5.2 5.4 5.4 5.3 5.2 5.1 5.3 5.1 4.6 4.9 5.0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 Power emissions -36%, -900 million metric tons 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Obama 2025 goal Biden 2030 goal Renewables ■ Other ■from coal electric power ■from natural gas electric power from other electric power from other sectors Under the original Paris Agreement, U.S. was to reduce 2005-level CO2 emissions 26-28% by 2025 Source: U.S. EIA Electricity Data Browser (net generation) & Monthly Energy Review (April-2023); World Bank, Development Indicators, GDP, U.S.$ current. 15#16Replacing Coal Could Likewise Accelerate Global Emissions Reductions POTENTIAL FOR LOWER GLOBAL EMISSIONS Mt CO2 36,639 KINDER MORGAN Potential Net 9,394 Reduction of 26% 27,245 2021 total global CO2 emissions decrease in coal emissions (mostly attributable to coal to natural gas switching) 2050 potential global CO2 emissions Based on IEA data from the IEA (2022) World Energy Outlook, World Energy Outlook 2022 - Analysis – IEA. All rights reserved; presentation modified by Kinder Morgan (data unchanged). STEPS scenario. The STEPS scenario assumes coal emissions decrease 5,243 Mt CO2 by 2050. A further 4,150 Mt CO2 could be reduced by replacing coal with natural gas. This figure is calculated by dividing 2050 coal emissions of 9,863 Mt CO2 by a coal emission intensity rate of 88 Mt CO2/EJ, then multiplying by a natural gas emission intensity rate of 51 Mt CO2/EJ. This yields an equivalent 2050 natural gas emissions figure of 5,713 Mt CO2. Potential additional emissions reduction is difference between 9,863 Mt CO2 and 5,713 Mt CO2. 16#17Reliable, Long-Duration Storage is Critical in Peak Demand Periods KINDER MORGAN DAILY AVERAGE OF WEEK-OVER-WEEK CHANGES IN U.S. WORKING GAS bcfd ■send-out ■build 20 -20 -40 -60 -80 Jan-2012 0 2014 polar vortex ~41 bcfd Jan-2013 Jan-2014 Jan-2015 Jan-2016 Jan-2017 bcfd Uri 2018 polar vortex ~51 ~48 bcfd Jan-2018 Jan-2019 Peak weather events have historically required 40-50 bcfd of natural gas storage send-out Jan-2020 Jan-2021 Jan-2022 Jan-2023 DAILY POWER EQUIVALENT TWh per day 6.1 50 bcfd natural gas storage send-out 2050 U.S. APS forecasts only ~1.5 TWh of daily battery capacity Reliability is critical during these weather events & batteries would have to be recharged the following day - assuming weather conditions permit 1.5 U.S. 2050 battery capacity under APS Left: EIA Weekly Underground Natural Gas Storage Report. KM analysis. Right: Based on IEA data from the IEA (2022) World Energy Outlook, World Energy Outlook 2022 - Analysis - IEA. All rights reserved; presentation modified by Kinder Morgan (data unchanged). APS = Announced Pledges Scenario. Note: Battery equivalent based on natural gas energy converted terawatt hours (TWh) at 0.29 TWh per day per 1 bcfd; then, energy storage converted into power equivalent using assumed 42% efficiency rate of a natural gas peaker plant. Battery storage capacity assumes 4-hour duration by multiplying capacity by 4. IEA utility-scale battery storage assumptions range from one to eight hours. 17#18Positioned for the Future of Energy KINDER MORGAN Our vast network of strategically-located energy infrastructure will continue delivering energy for decades to come Moving fuels of today U.S. is the world's most responsible producer of scale U.S. exports help meet global demand from emerging economies in need of affordable, modern energy Natural gas can rapidly lower emissions from the global power & industrial sectors, which still rely heavily on coal Flexible storage & delivery of natural gas facilitates increased use of renewables while avoiding power outages Our assets facilitate renewable blends with traditional fuels & the future Building new infrastructure networks is difficult, environmentally impactful & costly; existing assets are likely to remain valuable Some emerging renewable fuels can be moved on our assets today Current pipeline & storage assets could be upgraded or repurposed to handle renewables, lower carbon fuels, or other transition-driven products We will take a disciplined approach when evaluating new renewables opportunities Essential to a clean, reliable, affordable energy future 18#19VALUABLE NETWORKS Tall Cotton compressor station, Seminole, Texas#20Growing Demand for Our Natural Gas Transportation & Storage Assets Leading to Increased Value Natural Gas Transport KM NATURAL GAS TRANSPORT & SALES VOLUMES tbtud 39.2 39.8 41.0 41.5 35.3 30.8 30.4 31.4 KINDER MORGAN 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 $2.6bn stable, contracted, fee-based natural gas backlog at 3.7x multiple drops to the bottom-line 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 Strategic Planning Outlook, March 2023. U.S. working storage capacity per the EIA. Note: U.S. storage capacity data is only available through year-end 2021. 20#21Provide High-Value Natural Gas Takeaway in all Major Basins U.S. production expected to grow 23% by 2030 U.S. NATURAL GAS PRODUCTION RELEVANT TO OUR FOOTPRINT bcfd 35 41 Northeast +6 bcfd 27 Permian +11 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 Mojave EPNG 21 Haynesville +8 bcfd San Juan Permian Sierrita Horizon Utica Stagecoach KMIP Utopia Marcellus TGP Midstream Anadarko Arkoma Haynesville Midstream Elba Express SNG /KMLP GLNG FGT ELC LNG Terminals ◇ Processing/Treatment Plant • Gas Storage Production Basin SNG's Haynesville takeaway fully contracted Kinderhawk gathering system - additional growth through efficient capital expansions PHP GCX Eagle Ford Cypress 16 9 13 8 66 LO Rockies, stable Mid-Continent, -1 bcfd Eagle Ford +1 bcfd Fully contracted Permian, ~0.6 bcfd PHP expansion, and evaluating additional opportunities 4 2022 2023 2024 2025 2026 2027 2028 2029 2030 Source: WoodMackenzie, North America Gas Strategic Planning Outlook, March 2023. Note: Rockies predominately includes production from the Niobrara, Powder River, Bakken, Three Forks formations. 21#22Strong 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 127 106 LNG exports 11 LNG plant fuel 1 LNG exports 24 I LNG plant fuel 2 Industrial 32 Net Mexican exports 6 Residential & Commercial 23 Industrial 35 Net Mexican exports 9 Residential & Commercial 23 Power 33 Power 31 2022 2030 Midstream WIC NGPL CIG CP TCGT Mojave EPNG Sierrita Horizon Stagecoach LNG Terminals KMIP Utopia ◇ Processing/Treatment Plant Gas Storage TGP Midstream FEP MEP Midstream SNG Elba Express KMLP GLNG FGT Contracted to transport PHP ~4 bcfd to Mexico Cypress GCX 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 Strategic Planning Outlook, March 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 2 bcfd attributable to Transport and Blue Hydrogen sectors. 22#23Transporter 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 Contracted to move ~7 bcfd to facilities today & ~10 bcfd by the end of 2025 Evaluating ~10 bcfd of additional opportunities Texas Intrastate NGPL Louisiana Mississippi TGP SNG KMLP Lake Charles TGP Driftwood Cameron PHP Katy NGPL Henry Plaquemines Port Arthur Calcasieu Pass 27 27 Sabine Pass 25 Golden Pass 22 20 TGP Freeport 20 KM Contracted LNG Export Terminals Other Proposed/Existing LNG Export Terminals. Elba Liquefaction Project Market Hub 16 13 14 12 10 10 10 10 10 7 7 7 MPC GCX Corpus Christi California Agua Dulce 10 10 Rio Grande 2022 2023 2024 2025 2026 2027 2028 2029 2030 Source: WoodMackenzie, North America Gas Strategic Planning Outlook, March 2023. Note: WoodMackenzie exports are multiplied by 1.09 for an estimated feedgas figure. MPO Costa Azul LNG Baja California EPN Elba Express South Carolina Georgia ELC 23#24Extensive 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 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 KINDER MORGAN Stagecoach provides flexibility to serve NE Horizon power demand Stagecoach KMIP Utopia TGP Midstream FEP MEP Midstream SNG Elba Express ELC TGP provides significant seasonal and peak day deliveries to NE markets FGT & SNG fully contracted with significant LDC & KMLP GLNG FGT power demand PHP Cypress GCX LNG Terminals Processing/Treatment Plant Gas Storage Storage is key for LNG facilities which face interruptions from cargo scheduling changes, maintenance, & weather 24#25Continue to Serve the Permian's Growing Gas Takeaway Needs KINDER MORGAN EPNG: 3 bcfd NGPL: 375 mmcfd Permian Oklahoma EPNG Texas PHP: 2 bcfd + 0.6 bcfd expansion Expect Permian +11 bcfd by 2030(a) GCX: 2 bcfd NGPL Intrastates KM Intrastates system: a) Compared to 2022. Wood Mackenzie, North America Gas Strategic Planning Outlook, March 2023. 8.3 bcfd 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 Evaluating additional Permian transport opportunities 25#26Products 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 26#2722 27 Products 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 2 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#28Terminals 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 Bulk tonnage (mm tons) 100% TERMINALS SEGMENT VOLUMES & UTILIZATION Percent of liquids capacity leased 20 20 45 15 80% 60% Terminals KM Terminals-Liquids KM Products Pipelines 40% KM Terminals - Bulk Jones Act Tankers 20% -% 2019 2020 2021 2022 2023B 10 5 28#29Tankers Meeting Domestic Maritime Demand Most modern & efficient Jones Act tanker fleet American Petroleum Tankers 16 fuel-efficient Jones Act tankers Largest, most modern fleet with an average age of 8.8 years Dramatically improved Jones Act fundamentals Industry supply & demand dynamics have tightened considerably with 100% of the fleet presently utilized Trade flow disruptions for both crude and products associated with Russia/Ukraine crisis Nascent trans-Panama Canal trade for RD from USGC to USWC New statutory limitations on issuing waivers Strengthening charter rates further supported by new-build economics Spot time charter rates for Medium Range (MR) Jones Act tankers have improved from $58K/day at the end of 2021 to $75K/day(a) New-build MR capital cost estimated $200MM/vessel with earliest potential deliveries in 2027(a) Term charter rate required to underwrite such investment estimated at ~$100K/day(a) Significantly de-risked APT charter profile Percent of revenue days under firm charter: Bay State Garden State Palmetto State Magnolia State Lone Star State Golden State American Pride American Liberty American Endurance Pelican State American Freedom Pennsylvania Florida Evergreen State Empire State Sunshine State 2022 2023 2024 2025 As of Jan 2022 72% 19% 25% 25% As of Jan 2023 100% 93% 79% 65% a) Source: Wilson Gillette Report, December 2022 by Navigistics Consulting. b) Revenue Days calculated as 16 vessels x 365 days, adjusted for scheduled dry docks. KINDER MORGAN ■firm charter renewal option 2023 2024 2025 Average firm charter term remaining has improved from 1.3 years at the beginning of 2022 to 3.3 years today 29#30Industry-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 $52 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 30#31CO2 Segment Overview World class, fully-integrated assets | CO2 source to crude oil production & takeaway in the Permian Basin Interest in 5 oil fields with 9.2 billion barrels of Original Oil In Place Interest in 3 CO₂ fields with 37 tcf of Original Gas In Place Doe Canyon KINDER MORGAN CO2 EOR & TRANSPORT FREE CASH FLOW ■FCF □ Capex ◇ Adj. Segment EBDA Colorado CO2 pipelines CO2 source fields ☑Oil fields $ millions McElmo Dome Crude pipelines Permian basin Cortez New Mexico Bravo Dome $789 $777 $746 $707 $652 $185 $275 $242 $186 $349 $561 $514 $535 $466 $358 Katz 2019 2020 2021 2022 2023B Denver City SACROC Tall Cotton Snyder Midland SIZEABLE MARGIN ON OIL PRODUCTION $ per net barrel ■Cash costs ◆ Avg. realized oil price ~1,500 miles of CO2 $80 El Paso Wink Goldsmith $53.78 pipelines with $52.71 Yates $60 $49.49 McCamey capacity to move up to 1.5 bcfd Texas Iraan $40 $20 $- 2019 2020 2021 $66.78 $64.19 cash costs ~$25/barrel 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. 31#32Growing RNG Portfolio KINDER MORGAN LANDFILL-RNG ANNUAL PRODUCTION CAPACITY net to KM GROWTH PLAN Potential to grow +0.6 bcf over next operational (2.3 bcf gross) decade with little capex 1.8 bcf operational (2.3 bcf gross) +3.9 bcf expected online 2023 +up to 0.7 bcf 2024+ =6.4 bcf (6.9 bcf gross) PRIMARILY CONTRACTED IN TRANSPORTATION MARKET TODAY Long-term contracts in transportation/RIN market Up to $250 million development capex Short term contracted into RINS market, optionality for RNG or eRINs on acquired assets Expect -6x 2024 Project EBITDA based on ~$1.1bn total RNG portfolio investment Opportunity for fixed-price contracts will grow as voluntary market develops 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 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. 32#33KINDER MORGAN Red Cedar Carbon Capture and Sequestration 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 submitted to the EPA as well as permit modifications to Texas Railroad Commission Net capital investment of less than $50 million Project returns competitive with traditional business Target in-service by Q2 2024 El Paso Colorado Red Cedar Facilities Cortez New Mexico CO2 pipelines ☑Oil fields Denver City SACROC Tall Cotton Snyder Midland Goldsmith Katz Yates McCamey Texas Iraan Ownership in RCG JV, existing CO2 pipeline network, and downhole experience allow KM to participate in the entire CCS project value chain 33#34Recognized as an ESG Leader Highly rated by multiple agencies improved ratings by publishing EEO-1 report and responding to CDP KINDER MORGAN FTSE #3 of Oil & Gas Pipelines subsector MSCI A Oil & Gas Refining, Marketing, Transportation & Storage Industry Sustainalytics #2 of 117 Oil & Gas Storage & Transportation & # 3 of 199 Refiners & Pipelines Refinitiv #5 of 233 Oil & Gas Related Equipment and Services Companies Moody's #2 of 43 Oil Equipment & Services North America SSGA top 10% R-Factor in Oil & Gas Midstream sector Featured 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 April 2023. 34#35Compelling 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 ~6.5% current yield & healthy dividend coverage Top 10 dividend yield in the S&P500 ~$1.94 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. 35#36APPENDIX Terminal Pit 11, Pasadena, Texas#37Stable, Growing U.S. Production U.S. NATURAL GAS PRODUCTION bcfd 108 102 96 90 00 84 78 Production increases to 106 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 Strategic Planning Outlook, March 2023. Right: EIA 2023 Annual Energy Outlook (March 2023). 37#38& 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 KINDER MORGAN SHORT-TERM PRODUCTION OUTLOOK dry gas, bcfd, 2019 - 2024 15 10 2,000 3,325 bbtud in Q1'23 3,668 bbtud 2023B 2024 +24% from 2020 trough 5 1,000 2024 +56% over pre-COVID levels 2024 +34% over pre-COVID levels 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 1Q23 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 Strategic Planning Outlook, March 2023. Eagle Ford Haynesville/CV Bakken / Three Forks 38#39Refined Products Volumes Continue to Recover GASOLINE mbbld 1,200 2022 2023B DIESEL mbbld 2023B 1,200 -2022 JET FUEL mbbld 2022 1,200 1,000 800 600 400 200 1,000 800 600 400 200 1,000 800 600 400 200 2023B KINDER MORGAN 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Q1'23: 948 mbbld 328 mbbld 271 mbbld 2023B: 992 mbbld 2022: 978 mbbld Modestly above 2022 Note: Kinder Morgan Refined Products volumes include SFPP, CALNEV, Central Florida & PPL (KM share). 395 mbbld 367 mbbld Expected to rebound throughout the year 277 mbbld 264 mbbld Continuing to strengthen 39#40Products Segment Crude Volume Update Business as % of 2023B KMI Adjusted Segment EBDA: 1% Crude Gathering; 3% Crude Transport CRUDE TRANSPORT & GATHERING VOLUMES(a) mbbld KINDER MORGAN SHORT-TERM PRODUCTION OUTLOOK 2019 – 2023 crude, mmbld 900 600 300 3Q20 2Q20 1Q20 4Q19 3Q19 2Q19 1Q19 1Q23 4Q22 3Q22 2Q22 1Q22 4Q21 3Q21 2Q21 1Q21 4Q20 1.5 1.0 0.5 2023 +12% vs 2022 2023 +7% vs 2022 Bakken Eagle Ford Crude: 460 mbbld in Q1'23 | 510 mbbld 2023B Note: Adjusted Segment EBDA is a non-GAAP measure. See Non-GAAP Financial Measures & Reconciliations. Production outlook from S&P Global Commodity Insights & EIA data. a) Includes volumes from KMCC, Camino Crude, Double Eagle (KM Share), Double H, and Hiland Crude. 40#41Our Integrated Terminal Network on the Houston Ship Channel KINDER MORGAN Refined products focused with an irreplaceable collection of assets, capabilities & market-making connectivity Our unmatched scale & flexibility: 43 million barrels total capacity 31 inbound pipelines 18 outbound pipelines 16 cross-channel pipelines 11 ship docks Galena Park West Galena Park Chevron Splitter KM Export Terminal Pasadena Pasadena Colonial Explorer Other Destinations Greens Port & North Docks Channelview KM terminals & assets refined products terminals local refineries & processing truck racks rail inbound & outbound marine docks Mont Belvieu ExxonMobil Baytown Deepwater Deer Park Refining Shell/Pemex BOSTCO Refining Chevron 39 barge spots Valero Houston Houston Refining LyondellBasell KMCC 35 truck bays 3 unit train facilities Over $2.2 billion invested since 2010 Shell P66 Marathon Exxon Jefferson Street P66 Sweeny Marathon Texas City Marathon Galveston Bay Valero Texas City 41#42Energy 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 42#43RNG Market Opportunity KINDER MORGAN U.S. RNG PRODUCTION bcfd expect landfills to drive growth 3.0 0.6 0.4 1.0 1.6 2.3 3.6 2022 2025 2030 2035 2040 2045 2050 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: $2.41/MMBtu 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: $22.98/MMBtu D3 RIN value (b) government program incentivizes RNG production, provides margin for producer 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 slimmer margin but fixed- price, 10+ year contracts EPA ERIN proposal beginning in 2024 provides additional markets for RNG & landfill gas to electric projects Sources: U.S. RNG production per WoodMackenzie, North America Gas Strategic Planning Outlook, March 2023. Includes all forms of RNG production. a) Emissions data per the EPA. b) $1.96 2023 D3 RIN price (per Argus) multiplied by 11.727 to convert to $/MMBtu. Pricing as of 4/28/2023. 43#447% Commodity- price based 40% 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 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. 44#452023 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. 45#46Minimum 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 46#47KINDER MORGAN ESG Strategy Provide energy transportation & storage services in a safe, efficient, and environmentally responsible manner for the benefit of people, communities, and businesses Environmental Invest in lower carbon future Grow natural gas transmission, RSG, RNG, and LNG businesses Invest in renewable fuel midstream assets Evaluate CCUS & hydrogen opportunities Energy transition ventures group explores opportunities beyond our core business Work to minimize environmental impact from our operations Work to reduce emissions Restore & protect biodiversity Social Safety-focused culture Build & maintain relationships with stakeholders where we operate Foster a diverse, inclusive, and respectful workplace Support employee career development Expect employees & representatives to adhere to our Code of Business Conduct and Ethics and Supplier Code of Conduct Governance Risks & opportunities are monitored and communicated to leadership Board evaluates long-term business strategy for resilience & adaptability Board committees include EHS (including ESG), Audit, Compensation, and Nominating & Governance Operations Management System establishes routine risk management activities 47#48Supporting a Lower Carbon Future & Enabling Our Customers to Meet Their GHG Goals KINDER MORGAN Methane emission reductions & transparent disclosure Annual or more frequent compressor station leak surveys on natural gas transmission & storage and target for gathering & boosting assets Founding member of ONE Future; natural gas T&S methane intensity of 0.03% vs. 0.31% target Avoided 133 bcf of methane emissions or 71mm MT of CO₂e since 1993 (6.65 bcf/year) Avoided 276,000 metric tons of CO₂e in 2021 from use of DRA TCFD aligned disclosure including limited assurance of Scope 1, Scope 2, & GHG Intensity Economic opportunities to participate in energy transition -80% of 2023B discretionary capital allocated towards lower carbon fuels Installing vapor recovery units in Houston Ship Channel - 38% GHG reduction from 2019 Existing RNG development portfolio of up to 6.9 bcf per year of gross production capacity 10 existing RNG pipeline interconnects with total capacity of 36 mmcfd. 3 additional RNG interconnects under construction with capacity of 9 mmcfd Leveraging CO₂ experience to participate in developing CCUS market R&D for new technologies Cheniere-led QMRV project - quantifying, monitoring, reporting, & verifying GHG emissions New York State's Emission Measurement Project - methane monitoring and measurement technology testing Methane Emissions Technology Evaluation Center Advisory Board Membership Understanding the effects of blending & transporting hydrogen through our existing pipeline infrastructure Research on storing hydrogen in repurposed underground natural gas storage facilities Note: Lower carbon fuels include conventional natural gas, responsibly sourced natural gas, RNG, LNG, renewable diesel, other biofuels, biofuel feedstocks, and CCS. 48#49Avoided or reduced 17.1mm metric tons CO2e in 2021 CO₂e avoided/reduced Infrastructure is Essential to Reduce & Avoid GHG Emissions ONGOING ACTIVITES ANNOUNCED PROJECTS Potential to avoid or reduce 9.5mm metric tons CO2e annually Annual CO₂e avoided/reduced KINDER MORGAN 2021 Activities (metric tons) Projects (metric tons) In-service date Ethanol(a) 10,900,000 RNG production(d) 3,900,000 2023-2024 Voluntary methane reductions - Methane Challenge (b) 3,600,000 Renewable feedstock hubs (c) 2,300,000 Q2'23/Q4'24 Biodiesel(c) California renewable diesel (c) 2,000,000 Q1'23(e) 1,350,000 622,000 307,000 276,000 749 Renewable diesel (c) RNG interconnects DRA use on Products Pipelines Solar panels Note: Blue highlighted activities and projects directly reduce or avoid KM Scope 1 or 2 GHG emissions. All other activities reduce third-party emissions. a) Assumes a 20% reduction in life cycle emissions compared to gasoline, per the Renewable Fuel Standard (RFS) requirement for renewable fuels life cycle reduction. b) Voluntary methane emission reductions include reductions from compressor station leak repairs, pipeline pumpdowns, gas turbine installations, electric motor installations, and alternative pipeline maintenance technologies that reduce the need for pipeline blowdowns. c) Assumes a 50% reduction in life cycle emissions compared to diesel, per the RFS requirement for biodiesel fuels life cycle reduction. d) Includes 1,300,000 MT CO₂e attributable to in-service RNG facilities (Indy HBTU and Arlington). e) Expect majority of Southern CA and Northern CA renewable fuels projects in-service during 1Q 2023. Total CO₂e emissions avoided/reduced from ongoing & announced projects: 26.6mm metric tons per year, equivalent to: 61mm barrels of oil consumed 2,988mm gallons of gasoline consumed carbon sequestered by 32mm acres of U.S. forest RNG interconnects 865,000 Varies CCS Red Cedar 400,000 Q2'24 VRU's Houston Ship Channel 34,000 Q3'23 49#50NON-GAAP FINANCIAL MEASURES & RECONCILIATIONS Elba liquefaction, Elba Island, Georgia ISd 600#51KINDER 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. 51#52Use 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. 52#53GAAP 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. 53#54Net 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) DCF 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 $ 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 $ 1.11 SASASA 1.12 $ 1.12 $ $ 1.16 $ (0.05) (4%) $ 2.13 $ 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. 54#55Net 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. 55#56Reconciliations 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 315 $ $ 5,043 $ 4,748 $ 4,550 $ 5,708 $ 4,967 (2,904) (2,270) (1,707) (1,281) (1,621) 2,139 2,478 2,843 4,427 3,346 (1,774) (2,163) (2,362) (2,443) (2,504) $ 365 $ 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 56#57Reconciliation 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 57