#1INVESTOR PRESENTATION February 2021 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. 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 long-term demand for our assets and services, 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 impacts of the COVID-19 pandemic; 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; 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, 2020 (under the headings "Risk Factors," "Information Regarding Forward-Looking Statements" and elsewhere) and our subsequent reports filed with the SEC. 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, as well as reconciliations of historical non-GAAP financial measures to their most directly comparable GAAP measures, can be found in thispresentation 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 Unparalleled & irreplaceable asset footprint built over decades Largest natural gas transmission network ~70,000 miles of natural gas pipelines 659 bcf of working storage capacity ~1,200 miles of natural gas liquids pipelines Largest independent transporter of refined products Transport ~1.7 mmbbld of refined products Pacific Northem Ruby ~6,800 miles of refined products pipelines ~3,100 miles of crude pipelines Largest independent terminal operator 144 terminals & 16 Jones Act vessels Largest CO2 transport capacity of ~1.5 bcfd ~1,500 miles of CO2 pipelines BUSINESS MIX 62% 16% 15% 7% ■ Natural gas ■ Products ■ Terminals ■ CO2 TCGT Calnev Mojave KINDER MORGAN KM Midstream Connecting major U.S. natural gas resource plays to key demand centers Move ~40% of U.S. natural gas consumption & exports Double H MC CIG CP NGPL KM Midstream EPNG Cortez FEP Utopia TGP PPL Elba Express SNG ELC Pacific MEP Sierrita, Wink KM Midstream KMLP GLNG FGT PHP GCX Cypress KMCC/ Double Eagle CFPL NATURAL GAS PRODUCTS TERMINALS CO₂ • storage processing LNG terminals terminals A terminals ☐ CO₂ source fields 16 Jones Act tankers A oil fields Note: Mileage & volumes are company-wide per 2021 budget. Business mix based on 2021 budgeted Adjusted Segment EBDA. See Non-GAAP Financial Measures & Reconciliations. 3#4KMI: a Core Holding in Any Portfolio Generating significant cash flow & returning significant value to shareholders >$35 billion market capitalization KINDER MORGAN One of the 10 largest energy companies in the S&P500 ~13% owned by management Highly-aligned management with significant equity interests ~7% current dividend yield $2 billion share buyback program Top 10 dividend yield in S&P500 Expect to declare 3% dividend increase in 2021 vs. 2020 Expect up to $450 million available for buybacks in 2021 while maintaining BBB balance sheet 4#52021 Budget Committed to maintaining a strong balance sheet & returning value to shareholders Key metrics Net income 2021 Budget Variance to 2020 $2.1 billion ~$2 billion Increase due primarily to impairments taken during 2020 Adjusted EBITDA $6.8 billion (2)% Distributable Cash Flow $4.4 billion (3)% (DCF) Discretionary capital(a) $0.8 billion Dividend/share(b) $1.08 3% Year-end Net Debt / 4.6x Adj. EBITDA (b) KINDER MORGAN Lower re-contracting rates (mainly Ruby & FEP, as noted for the last couple of years), lower oil volumes, lower realized oil prices & lower capitalized overhead Partially offset by projects placed in service, increased refined product volumes & a corporate-wide organizational efficiency & effectiveness project Also impacting DCF is higher anticipated sustaining capex & lower interest expense $1.2 billion DCF in excess of discretionary capital (a) & dividends Up to $450mm $450 million available for share repurchases Note: See Non-GAAP Financial Measures & Reconciliations. a) Includes growth capital & JV contributions for expansion capital, debt repayments & net of partner contributions for our consolidated JVs. b) No share repurchases assumed in 2021 budget. 5#6Strategy 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 >90% take-or-pay & fee-based cash flows Invest in a low carbon future $1.5 billion backlog with 60% allocated to natural gas projects Allocated ~70% of 2020 expansion capex to natural gas & LNG projects Invested in biodiesel, ethanol & renewable diesel projects Financial flexibility 4.6x 2021 budgeted Net Debt/Adjusted EBITDA (a) consistent with 4.5x target Low cost of capital Mid-BBB credit ratings Ample liquidity Disciplined capital allocation Conservative assumptions High return thresholds Self-funding 100% of capex & dividends for last five years Enhance shareholder value Maintain strong balance sheet Attractive projects Dividend growth Share repurchases a) See Non-GAAP Financial Measures & Reconciliations. K 6#7Highly-Contracted Cash Flows Stable cash flows with ~72% take-or-pay or hedged earnings (a) Contract type Payment feature KINDER MORGAN Example assets CONTRACT MIX(a) 68% Take-or-pay Entitled to payment regardless of throughput Natural gas intrastate (b) Reservation fee for capacity Jones Act tankers 100% Natural gas interstate / LNG 93% 83% CO2 & transport 78% Liquids terminals 74% Crude pipes 69% Crude G&P 93% Adjusted Segment EBDA 25% Fee-based Fixed fee collected regardless of commodity price Refined products pipes 89% Bulk terminals 68% Volumetric-based revenues Natural gas G&P 62% 4% Hedged Disciplined approach to managing price volatility EOR oil & gas (c) 80% Substantially hedged near-term price exposure b) c) EOR oil & gas (c) 20% 3% Other Commodity-price based Crude pipes 12% Natural gas G&P 10% Based on Adjusted Segment EBDA per the 2021 budget. See Non-GAAP Financial Measures & Reconciliations. Includes term sale portfolio. Percentage of net crude oil, propane & heavy NGL (C4+) net equity production per the 2021 budget. 7#8Customers Are Primarily End-Users of the Products We Handle KINDER MORGAN Net revenues underpinned by investment grade counterparties & credit support | Ratings as of January 11, 2021 CUSTOMER TYPE ■ End-user ■ Producer - IG or substantial credit support ■ Producer - non-IG or not rated ■ Midstream Marketer 3% 6% 8% 12% >70% end-users such as large integrated energy, utilities, refiners & other industrial users 71% CREDIT RATING ■IG or substantial credit support ■ BB+ to B ■ B- or below ■ Not rated 12% 13% ~74% investment grade rated or substantial credit support 74% Only ~1% of exposure from B- or below rated customers, including non-rated customers in bankruptcy, after collateral & remarketing efforts Note: Based on 2021 budgeted net revenues, which include our share of unconsolidated joint ventures & net margin for our Texas Intrastate customers & other midstream businesses. Pie charts includes 232 customers >$5mm at their respective company credit ratings per S&P, Moody's & Fitch, shown at the S&P-equivalent rating & utilizing a blended rate for split-rated companies, which represent -85% of total net revenues. 8#9Self-Funding Capex & Dividends Since 2016 Opportunistic asset monetization enabled meaningful debt reduction Generated $1.9 billion of free cash flow after dividends over last 5 years Asset sales, net CFFO Borrowing, net Cash from BS Buybacks Other(a) Asset sales, Cash to BS net Cash to BS Other(a) Asset sales, net Debt repayment Debt repayment Dividends Dividends CFFO CapEx CapEx Sources Uses 2016 Sources Uses 2017 CFFO Other(a) Buybacks Dividends CapEx Sources Uses 2018 Cash from BS Debt repayment Other(a) Asset sales, net Dist. of KML proceeds Contrib. to JVs, net CFFO Dividends CapEx Sources Uses 2019 KINDER MORGAN Asset sales, net Cash to BS Other(a) Dividends CFFO CapEx Sources Uses 2020 Source: KMI GAAP Statement of Cash Flows. 2020 results are preliminary. Note: Free cash flow = CFFO less capital expenditures. See non-GAAP Financial Measures & Reconciliations. "Asset sales, net" include the monetization of a 50% interest in Southern Natural Gas, Kinder Morgan Canada Limited (KML IPO & sale), Trans Mountain pipeline & U.S. Cochin pipeline. (a) Unless called out separately, "Other" includes (i) contributions to JVs, (ii) distributions from JVs included in cash flow from investing, (iii) net distributions to NCI, (iv) debt repayment, net of issuances, (v) share buybacks, (vi) the effect of FX on cash & (vii) other, net. 9#10KINDER MORGAN Our Business is Resilient throughout an Energy Transition what we do today... is valuable & will be needed for a long time helps meet environmental goals "energy transitions take decades" - Vaclav Smil, Distinguished Professor Emeritus in the Faculty of Environment, Univ. of Manitoba "whichever way things evolve, fuels of various kinds will be essential to the future of energy" - International Energy Agency infrastructure supporting the displacement of higher emissions energy sources (e.g. coal) management emphasis on reducing emissions & meeting ESG objectives in our existing business ...positions us for the energy business of the future 10 10#11All Available Sources Required to Meet Demand Outlook Even as the energy mix gradually shifts, hydrocarbons projected to remain essential to meeting demand GLOBAL PRIMARY ENERGY DEMAND BY FUEL billions tons oil equivalent (btoe) | 2019, 2030, 2040 5 total demand & % mix KINDER MORGAN 3 2 1 Overall energy demand expected to grow nearly 20% 3% 5% 8% 3% 5% 11% 2% 9% 19% 26% Oil Natural gas Coal Bioenergy +7% +29% -12% +34% Other renewables +344% Nuclear Hydro +23% +37% Source: International Energy Agency, World Energy Outlook, October 2020 (Total Primary Demand in Stated Policies Scenario). Note: Other renewables include geothermal, solar photovoltaics (PV), concentrating solar power (CSP), wind & marine (tide & wave) energy for electricity & heat generation. 25% 23% 31% 28% 2019 2040 14.4 btoe 17.1 btoe 11#12Substantial Growth Projected for U.S. Natural Gas KEY BASINS DRIVING U.S. GROWTH 2020 to 2030 growth in bcfd 9 9 Additional 24 bcfd expected from three areas. 6 Haynesville Permian Northeast DEMAND in bcfd Exports & industrial driving. majority of growth 2020 31 22 LO 31 6 96 Powder River Bakken Green River Denver Uinta Piceance Anadarko San Juan Permian Eagle Akroma KINDER MORGAN Utica Marcellus Haynesville LNG terminals processing/treating plant gas storage >80% of forecast demand growth is driven by TX & LA 2030 31 23 7 36 18 116 ■ Power Transport Residential & Commercial ■Net Mexican exports Industrial ■LNG exports Our network connects key supply basins to multiple demand points along the Gulf Coast Source: WoodMackenzie, North America Gas Markets Long-Term Outlook, December 2020. Growth relative to projected 2020 production at the time of the report. Total U.S. natural gas production to grow by 18 bcfd by 2030; forecast assumes aggregate of other U.S. basins shrinks by 6 bcfd. Industrial sector includes Wood Mackenzie's "Other" category, comprised of lease and plant fuel and fuel used for liquefaction at export facilities. 12#13Our Infrastructure is Important to Fueling the Future KINDER MORGAN Leveraging our long-term investment in the substantial assets & expertise required to responsibly deliver energy BENEFITS OF NATURAL GAS LOW EMISSIONS Natural gas is the cleanest burning fossil fuel with significantly lower emissions than coal or fuel oil Switching from coal to natural gas has driven a substantial reduction in U.S. power sector CO2 emissions Helps meet environmental targets RELIABLE Provides energy supply when renewable sources are intermittent Can be dispatched quickly ABUNDANT & LOW COST Cost-effective generation Uses substantial infrastructure already in-place Helps maintain affordability for consumers ENERGY DENSE & EFFICIENT Less land area required compared to alternative energy sources Helps avoid additional land disturbances Natural gas enables economic growth without sacrificing environmental objectives Our irreplaceable assets are essential to moving the fuels of today & tomorrow 13#1422% 49% 2007 23% 2019 ■ Coal ■Natural gas ■Renewables ■ Other from other electric power from other sectors Under the Paris Agreement, U.S. was to reduce 2005-level CO2 emissions 26-28% by 2025 By 2019, over half of that reduction goal was already achieved Source: U.S. EIA Electricity Data Browser (net generation) & Monthly Energy Review (Dec-2020); World Bank, Development Indicators, GDP, U.S.$ current (12/16/2020). 14 8% 17% 21% 21% 38% 1990 1991 1992 1993 1994 1995 from coal electric power from natural gas electric power 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Power emissions declined >30% or ~805 million metric tons 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 6.0 5.9 5.8 5.4 5.6 5.4 5.2 5.4 5.4 5.3 5.2 5.1 5.3 5.1 U.S. CO2 Emissions Declined Since 2007 while GDP grew ~50% Primarily due to converting coal power generation to natural gas generation U.S. ELECTRICITY GENERATION MIX % of total generation U.S. CO2 EMISSIONS billion metric tons KINDER MORGAN U.S. emissions declined ~14% or ~860 million metric tons 2014 2015 4.4 2016 2017 2018 2019 2025 goal#15KINDER MORGAN Well-Positioned to Move Potential Fuels of the Future RNG & hydrogen can utilize much of the existing natural gas infrastructure network RNG is a pipeline-quality gas that is interchangeable with conventional natural gas Can be transported, stored & used in the same applications as natural gas Hydrogen could be shipped on natural gas pipelines in 5% to 10% blends with little to no modification Depends on pipeline metallurgy, age & other operating parameters Hydrogen is energy dense & well suited to long-distance transportation Pipelines can transport hydrogen more efficiently than transmission lines(a) Volumetrically, hydrogen is 1/3 as Larger quantities energy dense as natural gas May require -3x the capacity to transport equivalent amounts of energy 10-20x cheaper Avoids the electricity losses 5-10% -3x infrastructure capacity "Existing gas infrastructure is a valuable asset with significant storage capacity that can be repurposed over time to deliver large volumes of biomethane or, with modifications, low-carbon hydrogen" - IEA a) Source: Becker, Meike. "All hydrogen roads lead to renewables (and through Rome?)" Sanford C. Bernstein & Co., LLC. September 3, 2020. 15#16Opportunity for Natural Gas Infrastructure KINDER MORGAN Renewable alternatives are small in scale today, but could grow to meet nearly 20% of current U.S. demand as costs decline U.S. SUPPLY bcfd, 2020 & 2050 potential 120 100 08 80 660 40 40 20 20 RNG Hydrogen Natural gas COST ESTIMATES $ per Dth | 2020, 2030, & 2050 $29.00 $25.50 $33.44 $22.00 $21.55 4 $18.58 $15.00 $13.50 $9.50 $12.00 $8.00 $10.77 $8.17 RNG $4.50 $2.50 $3.00 $1.00 Natural gas $5.94 Green H2 Similar to the way natural gas is used today: Both can be transported as a gas by pipelines, moved in liquid form by ships & stored in geologic caverns & depleted reservoirs Could help decarbonize many sectors & applications: fuel for power & transport, heat for industry & buildings, feedstock for chemicals, etc. Source: 2020 U.S. RNG supply estimated from EPA. 2050 U.S. RNG supply potential from NREL. "Energy Analysis - Biogas Potential in the United States." October 2013. 2020 U.S. hydrogen supply estimated from EIA. 2050 U.S. hydrogen supply potential from Hydrogen Council. "Hydrogen scaling up: A sustainable pathway for the global energy transition." November 2017. Cost estimates from IEA & KM analysis. Current U.S. natural gas demand based on 2020 estimate of 96 bcfd (including exports) from Wood Mackenzie Fall 2020 Long Term Outlook. 16#17Attractive Potential for Liquid Biofuels KINDER MORGAN Policy support & efficient infrastructure important to increasing adoption of ethanol, biodiesel & other low-carbon fuels GLOBAL BIOFUELS DEMAND OUTLOOK million barrels per day 6 5 4 3 2 1 0 2019 2025 2030 2040 Stated policies scenario projects: ~75% or 1.5 mmbbld increase by 2030 ~150% or 3.0 mmbbld increase by 2040. Even more in a 2-degree scenario ~40% of growth from the U.S. & China Policies such as the U.S. Renewable Fuel Standard & China's E10 program underpin this level of increase 5x more investment required each year Over $10 billion projected to be spent on production capacity through 2030 versus just $2 billion in 2019 Source: International Energy Agency, World Energy Outlook, October 2020 (Stated Policies Scenario). Note: Statistics relative to 2019, the latest actual available. 17#18Substantial Existing Capabilities at Our Terminals & Products Assets Includes substantial blending, pipeline, terminaling & export capabilities for ethanol & other biofuels KINDER MORGAN Our existing assets offer many biofuels capabilities: Ethanol Fuel-grade ethanol breakout (e.g., unit-train transloading) & blending into gasoline (e.g., truck racks) Multi-modal ethanol hubs, including our Argo terminal which is the CME pricing & trading point for Chicago ethanol Biodiesel Biodiesel services include transloading, storage & blending in tank, at the truck rack & in pipeline manifolds Project currently under construction at Barstow Terminal (CALNEV); also includes some RD capability Renewable Diesel Services include storage, blending, marine, rail & truck handling Terminals segment services focused in Midwest & Lower River area Products segment can handle up to R5 blends on diesel systems (a) In 2020, our Products & Terminals segments handled: ~240 mbbld 2020 U.S. production (b); ~902 mbbld ~13 mbbld ~118 mbbld ~5 mbbld Evaluating multiple opportunities to establish hubs for renewable products / biofuels Source: U.S. production from EIA Weekly U.S. Oxygenate Plant Production of Fuel Ethanol (1/6/2021) & Monthly Biodiesel Report (12/31/2020). a) Based on current regulatory requirements. Absent regulatory requirements, capability would be R0 to R100 as renewable diesel is chemically indistinguishable from hydrocarbon diesel. b) Biodiesel represents average daily volume for the 10 months ended 10/31/2020, the latest available as of January 2021. 18#19West Coast Renewable Fuels Projects Developing infrastructure to secure renewable fuels Market drivers Renewable Diesel (RD) has been driven by California subsidies RIN credits Low Carbon Fuel Standard (LCFS) credits Blender's Tax Credit Currently averaging approximately $3.00/gal for total credits (RIN+LCFS+ Blender's tax credits) State goals to reduce emissions CARB has 2030 goal to reduce 1990-level GHG emissions by 40% Oregon's Clean Transportation Fuel Standards program has aggressive goals for reducing carbon emissions Potential project highlights Construction of new RD hubs in both Northern & Southern California Approximately $90 million discretionary capex for all locations Rail in renewable diesel / biodiesel Segregated storage for renewable products Opportunities to blend RD with both biodiesel & CARB diesel over the truck rack - providing increased high-value optionality to customers Each hub location currently scoped for 20 mbbld renewable capacity with further expansion opportunities available Serving the entire California diesel market Biodiesel blend capabilities will increase from existing 5% limit to 20% Note: RIN = Renewable Identification Numbers. CARB = California Air Resources Board. Oakland Chico Bradshaw North Line San Jose Nevada California Calnev Los Angeles Colton San Diego Line West Line Indio KINDER MORGAN Legend Products Pipeline Refined Product Terminals Potential Renewable Diesel Sites Transmix Facilities Cities Towns Arizona New Mexico East Line 19#20Carbon Capture Utilization & Storage (CCUS) Positioned to leverage our existing expertise & capabilities to provide CCUS services in the future Our experience & current operations cover the CCUS value chain Design, manufacture, install & operate equipment needed for CO₂ separation Operate >1,300 miles of CO2 pipeline - more than any company in the U.S. with total system capacity of >3 bcfd Secure geologic storage of CO2 via CO2 enhanced oil recovery (EOR) Participate with other organizations to advance CCUS policy & technology Future opportunity to participate in CCUS Transportation of very large volumes of CO2 will be required in order to meet CCUS goals Converting other types of pipelines to long haul CO2 is rarely feasible Manufacture & installation of primarily new capture equipment necessary for 45Q eligibility EOR is widely viewed to be the best disposition for captured CO2, but the best EOR potential is distant from most major sources of CO2 KINDER MORGAN CURRENT ESTIMATED U.S. CARBON CAPTURE COST $/tonne $300 $250 $200 $150 $100 $50 וויי $0 ethanol production facility natural gas ammonia processing & production treating facility facilities cement production facility hydrogen coal fired natural gas production power plant fired power facility plant Given 45Q credits, CCUS is economic for some ethanol production, natural gas processing, and natural gas treating facilities Additional technological advancements & government policy could advance CCUS economics for other facilities Source: KM analysis, National Energy Technology Laboratory. Note: Estimated costs are based on 20% BFIT IRR at capture unit tailgate, no tax credits, and at pressure ready for pipeline. 20 20#21Our Multi-Faceted ESG Approach Recognized as an industry leader & for ongoing improvements INVEST integrity management & maintenance programs Safety-focused Outperform industry averages in almost all safety & release related categories Projects to minimize our impact on biodiversity within our operating areas MANAGE integrity, accountability, safety, excellence Employees & representatives expected to behave ethically & responsibly Employ sustainable business practices REPORT provide transparency to stakeholders Released third ESG Report, including 1.5-2°C scenario & physical risk analysis Utilizing SASB & TCFD frameworks Third party assurance & testing by internal audit Plan to report company-wide Scope 1 & 2 emissions in 2021 COLLABORATE engage communities & service suppliers Support & regularly interact with local communities Foster safety-focused culture among our service suppliers Strive to build relationships with diverse suppliers Sustainalytics ESG risk rating(a) #1 in Refiners & Pipelines industry group (182 companies) KINDER MORGAN #1 in Oil & Gas Storage & Transportation subindustry (95 companies) Featured in multiple ESG indices FTSE4Good Index series for ethical investments FTSE4Good MSCI USA ESG Leaders Index targeting the highest ESG rating in each sector of parent index S&P 500 ESG Index measuring performance of companies meeting sustainability criteria Recently named on Newsweek's list of America's Most Responsible Companies 2021 & upgraded to BBB ESG rating by MSCI Note: SASB = Sustainability Accounting Standards Board. TCFD = Task Force for Climate-Related Disclosure. a) As of 1/8/2021. 21 24#22Long-Standing Commitment to Reducing Emissions 25+ year track record Evaluate new opportunities Work with organizations like DOE, EPA, & PRCI on studies & technology evaluations $712k invested in GHG emissions & other climate-related R&D over past three years Set reduction goals for 2020 - Reduce methane emissions by 2.25 bcf or -1.2 MMT CO2e Part of ONE Future & EPA's Natural Gas STAR & Methane Challenge Employ programs & technology Energy management programs reduce our electricity usage Implement technology like satellite & aerial methane detection, & laser absorption monitoring Disclose Rated in top quartile of midstream sector for methane disclosures & quantitative targets by EDF Surpassed methane emissions intensity target(b) 0.03% vs. 0.31% target for natural gas transmission & storage assets in 2019 KINDER MORGAN SUCCESSFUL METHANE EMISSIONS REDUCTIONS(a) bcf, cumulative across our operations reported to EPA Natural Gas STAR & Methane Challenge programs (20) (40) (60) (80) >120 bcf (100) 7 years ahead (120) of schedule of emissions prevented 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Note: DOE = Department of Energy. EPA = U.S. Environmental Protection Agency. PRCI = Pipeline Research Council International. EDF = Environmental Defense Fund. a) Emission reductions are emissions mitigated or avoided that would otherwise have been emitted. b) Kinder Morgan's allocation of One Future methane emissions intensity target. 22 22#23Compelling Investment Opportunity Strategically-positioned assets generating substantial cash flow with attractive investment opportunities Pacific Northem Ruby TCGT Calnev Mojave NATURAL GAS storage processing LNG terminals • KM Midstream Double H PRODUCTS TERMINALS A terminals MC CIG CP NGPL KM Midstream EPNG Cortez FEP MEP terminals 16 Jones Act tankers Utopia TGP PPL CO CO, source fields oil fields Elba Express SNG. ELC Pacific Sierrita Wink KM Midstream KMLP GLNG FGT PHP GCX Cypress KMCC/ Double Eagle CFPL KINDER MORGAN Stable cash flows with ~72% take-or-pay or hedged earnings(a) ~7% current yield & almost 2x coverage (b) Top 10 dividend yield in S&P500 Dividends & capex funded with operating cash flow since 2016 Expect up to $450 million available for share repurchases in 2021 Highly-aligned management with ~13% share ownership Positioned for energy future with a vast network of critical assets & low-carbon focus Note: See Use of Non-GAAP Financial Measures. a) Based on Adjusted Segment EBDA per 2021 budget. See Non-GAAP Financial Measures & Reconciliations. b) Based on 2021 budgeted DCF to dividend coverage ratio. 23 23#24APPENDIX#25Natural Gas 62% Energy Toll Road Cash flow security with >90% from take-or-pay & other fee-based contracts 2021B EBDA %(a) Terminals 15% KINDER MORGAN Products 16% CO2 7% Interstate / LNG Intrastate G&P Refined products Crude Liquids terminals Jones Act tankers Bulk terminals EOR Oil & Gas CO₂ & Transport Asset Mix(a) 46% 10% 6% 11% 4% & 1% transport & G&P 9% 3% 3% 5% 2% take-or-pay(b) 81% fee-based with minimum volume requirements and/or acreage dedications Volume Security(a) 93% take-or-pay 83% primarily volume-based transport: 69% take-or-pay G&P: 98% fee-based 74% take-or-pay 100% take-or-pay primarily minimum volume volume-based guarantee or requirements effectively 84% minimum volume committed Average Remaining 6.4/19.7 years 5.7 years (b) 2.5 years generally not applicable 3.3 years 2.5 years 0.6 years 4.6 years 7.9 years Contract Life (c) Pricing Security primarily fixed based on contract primarily fixed margin primarily fixed price annual FERC tariff escalator (PPI-FG + 0.78%) primarily fixed based on contract >95% protected based on contract; typically fixed or tied to PPI volumes 80% hedged (d) by contractual price floors (a) Regulatory regulated return Security essentially market-based market-based Pipelines: regulated return Terminals & transmix: not price regulated(e) not price regulated primarily unregulated Commodity Price no direct limited exposure limited exposure limited exposure no direct exposure hedged / limited exposure exposure Exposure a) Based on Adjusted Segment EBDA per the 2021 budget. See Non-GAAP Financial Measures & Reconciliations. Amounts have been rounded. b) Includes term sale portfolio. c) As of 1/1/2021 d) Percentage of 2021 forecasted net crude oil, propane & heavy NGL (C4+) net equity production. e) Products terminals not FERC regulated, except portion of CALNEV. 25 25#26$1.5 Billion Project Backlog as of 12/31/2020 Primarily focused on contracted natural gas opportunities KINDER MORGAN DEMAND SUPPLY PULL PUSH CAPITAL ($ billion) ESTIMATED IN-SERVICE PIPELINE CAPACITY Supply for U.S. power & LDC demand (TGP, FGT & SNG) $ 0.4 Q1 2021 2023 0.6 bcfd Supply for LNG export (KMLP, NGPL, EPNG) Gathering & processing (primarily Hiland, Altamont & KinderHawk) 0.3 Q1 2021 2022 1.3 bcfd 0.1 Q1 2021 2022 various Other natural gas Natural Gas Terminals 0.1 Q4 2020 2022 ~0.3 bcfd $ 0.9 ~60% of total with 4.7x EBITDA build multiple on average 0.1 CO₂ 0.5 Total backlog $ 1.5 Note: See Non-GAAP Financial Measures & Reconciliations. EBITDA multiple reflects KM share of estimated capital divided by estimated Project EBITDA. 26 46#27KINDER MORGAN Supporting the Buildout of U.S. LNG Exports Serving significant liquefaction capacity & well-positioned to capture more Kinder Morgan network advantages Natural gas transportation leader ~70,000 miles of natural gas pipelines Move -40% of U.S. natural gas consumption & exports Supply diversity Connected to major U.S. natural gas resource plays Premier deliverability 659 bcf of working gas storage in production & market areas Transporter of choice Contracted capacity Average remaining Texas Intrastate NGPL Louisiana MEP Mississippi TGP KMLP SNG Lake Charles TGP Driftwood Katy Cameron NGPL PHP Henry Plaquemines Port Arthur- Calcasieu Pass Sabine Pass Golden Pass TGP Freeport PAG Calfomia GCX Corpus Christi contract term In active discussions Agua Dulcé online Contracted capacity to come ~ 4.4 befd 1.7bcfd 17 years 2-4 bcfd 2 Also deliver ~1 bcfd of producer / marketer supply Costa Azul LNG BAJA CALIFORNIA KM Contracted LNG Export Terminals Other Proposed/Existing LNG Export Terminals Elba Liquefaction Project Market Hub Arizona Elba Express Georgia South Carolina Rio Grande 27 22#28Manageable Natural Gas Re-Contracting Exposure Analysis of existing contracts that renew during next two years KMI ADJUSTED SEGMENT EBDA $ millions ■Adjusted Segment EBDA Interstate pipelines Intrastates & G&P $8,000 $7,000 KINDER MORGAN expected annual net re-contracting exposure Expiring contracts are assessed for volumetric & rate risk based on November 2020 market assumptions (time of budget) Excludes benefit of new cash flows from growth projects Excludes potential for re-purposing underutilized assets or otherwise enhancing service offerings Contracts on natural gas pipelines have average remaining term of 6 years Expect to more than offset re-contracting headwinds with growth projects underway, increases in usage, opportunities for currently uncontracted capacity & improved value for storage $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0 2017 2018 2019 2020 2021 Budget 2022 2023 2% of 2021B Primarily Ruby 1% of 2021B Primarily Copano S Texas legacy contracts Note: See Non-GAAP Financial Measures & Reconciliations for reconciliations of Adjusted EBITDA to its closest GAAP measure for 2020 and 2021 budget. For reconciliation of Adjusted EBITDA to its closest GAAP measure for the years 2017 through 2019, see KMI's Annual Reports on Form 10-K for the year-ended December 31, 2019 and 2018 filed with the Securities and Exchange Commission. 28#29Products Segment Overview Supplying a diverse mix of feedstock & finished products critical to refining & transportation sectors 2021B volumes Volume by KINDER MORGAN 2021B DELIVERY VOLUMES(a) 25% 12% 2,253 mbbld 16% mbbld region (b) West 74% Gasoline 1,054 Southeast 26% Diesel fuel 356 West 75% Southeast 25% Jet fuel 266 47% West 82% Southeast 18% Crude oil 577 Bakken 51% Texas 49% Budget averages 2% below 2019 gasoline volumes & reaches 2019 level by Q4 2021 Budget averages 2% below 2019 diesel volumes & reaches 2019 level by Q4 2021 Budget averages 12% below 2019 jet volumes & approaches 2019 level by Q4 2021 Supplying airports in Atlanta, Las Vegas, Orlando, San Francisco, Washington D.C. Positioned in premier basins in Texas & North Dakota KMCC provides access to Houston refining market & exports for Eagle Ford & Permian production Hiland is one of the Bakken's premier gathering systems Double H provides takeaway capacity from the Bakken to Cushing via joint tariff a) Kinder Morgan volumes include SFPP, CALNEV, Central Florida, PPL (KM share), KMCC, Camino Real, Double Eagle (KM share), Double H & Hiland Crude Gathering; Gasoline volumes include ethanol. b) Southeast Region Assets include Central Florida & PPL (KM share); West Region includes SFPP & CALNEV. Texas Crude Assets include KMCC, Camino Real, Double Eagle (KM share); Bakken Crude includes Double H & Hiland Crude Gathering. 29 29#30Our Integrated Terminal Network on 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 29 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 $2.1 billion invested since 2010 Note: Asset metrics include projects currently under construction. Shell P66 Marathon Exxon Jefferson Street P66 Sweeny Marathon Texas City Marathon Galveston Bay Valero Texas City 30#31KINDER MORGAN CO2 Segment Consistently Generates Free Cash Flow Low cash cost structure yields healthy margins through multiple commodity price cycles OIL & GAS CASH OPERATING COSTS & AVG. PRICE $ per net barrel ■Cash costs Avg. realized oil price CO2 SEGMENT FREE CASH FLOW $ millions ■FCF Capex ☐ Acquisitions Adj. Segment EBDA $70 $62 $58 $58 $60 $50 $40 $30 $20 $10 $919 $907 $887 $276 $54 $436 $397 $49 $49 $707 $652 $349 $186 $643 $504 $165 $489 $451 $466 $358 $339 Cash costs $20 / barrel 2016 2017 2018 2019 2020 2021B 2016 2017 2018 2019 2020 2021B Note: Cash costs & revenue per net oil barrel, including hedges where applicable. See Non-GAAP Financial Measures & Reconciliations for CO2 Free Cash Flow. 31#32Non-GAAP Financial Measures & Reconciliations Defined Terms Reconciliations for the historical periods KINDER MORGAN 32#33Use of Non-GAAP Financial Measures KINDER MORGAN We use the non-GAAP financial measures of Adjusted Earnings and Distributable Cash Flow (or DCF), both in the aggregate and per share for each; Adjusted Segment EBDA; Adjusted EBITDA; Net Debt; Net Debt to Adjusted EBITDA; Project EBITDA; Free Cash Flow; and CO2 Segment Free Cash Flow. Our non-GAAP financial measures described further below should not be considered alternatives to GAAP net income 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 these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes. We do not provide (i) budgeted revenue (the GAAP financial measure closest to net revenue) due to impracticality of predicting certain amounts required by GAAP, including projected commodity prices at the multiple purchase and sale points across certain intrastate pipeline systems; however, we are able to project the net revenue received for transportation services based on contractual agreements and historical operational experience; (ii) budgeted CO2 Segment EBDA (the GAAP financial measure most directly comparable to 2021 budgeted CO2 Segment Free Cash Flow) 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; or (iii) 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. 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, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view 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). Adjusted Earnings is calculated by adjusting net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our business's ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is net income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per share. DCF is calculated by adjusting net income attributable to Kinder Morgan, Inc. for Certain Items (or Adjusted Earnings, as defined above), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures" below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could beused for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided byoperating 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. 33 33#34Use of Non-GAAP Financial Measures (Continued) KINDER MORGAN 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. General and administrative expenses and certain corporate charges are generally not under the control of our segment operating managers, and therefore, are not included when we measure business segment operating performance. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assesseach 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 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 certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income. 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. 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. DCF and Adjusted EBITDA are further adjusted for certain KML activities attributable to our NCI in KML for the periods presented through KML's sale on December 16, 2019. Net Debt is calculated by subtracting from debt (i) cash and cash equivalents, (ii) the preferred interest in the general partner of Kinder Morgan Energy Partners L.P. (which was redeemed in January 2020), (iii) debt fair value adjustments, and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debtis debt net of cash and cash equivalents. 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." Management uses 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. Free Cash Flow is calculated by adjusting cash flow from operations for capital expenditures. Free Cash Flows is used by external users as an additional leverage metric. Therefore, we believe Free Cash Flow is useful to our investors. We believe the GAAP measure most directly comparable to Free Cash Flow is cash flow from operations. CO₂ Segment Free Cash Flow is calculated by reducing Segment EBDA (GAAP) for our CO2 business segment by Certain Items, capital expenditures (sustaining and expansion) and acquisitions attributable to the segment. Management uses CO2 Segment Free Cash Flow as an additional performance measure for our CO2 business segment. We believe the GAAP measure most directly comparable to CO2 Segment Free Cash Flow is Segment EBDA (GAAP) for our CO2 business segment. 34#35GAAP Reconciliations in millions 2021 2020 Change Budget Actual $ % Net income attributable to Kinder Morgan, Inc. (GAAP) $ 2,109 $ 119 $ 1,990 NM Total Certain Items (11) 1,892 (1,903) (101%) Adjusted Earnings (a) 2,098 2,011 $ 87 4% DD&A and amortization of excess cost of equity investments for DCF (b) 2,557 2,671 (114) (4%) Income tax expense for DCF (a,b) 659 670 (11) (2%) Cash taxes (c) (79) (68) (11) (16%) Sustaining capital expenditures Other items (e) (792) (658) (134) (20%) 2 (29) 31 107% $ 4,445 $ 4,597 $ (152) (3%) DCF Note: See Non-GAAP Financial Measures and Reconciliations. a) Amounts are adjusted for Certain Items. b) Includes DD&A or income tax expense, as applicable, from JVs. c) Includes cash taxes from JVs of $67 million and $62 million in 2021 and 2020, respectively. d) Includes sustaining capital expenditures from JVs of $119 million and $114 million in 2021 and 2020, respectively. e) Includes non-cash pension expense and non-cash compensation associated with our restricted stock program. Net income attributable to Kinder Morgan, Inc. (GAAP) Total Certain Items DD&A and amortization of excess cost of equity investments Income tax expense (a) JV DD&A and income tax expense (a)(b) Interest, net (a) Adjusted EBITDA Note: See Non-GAAP Financial Measures and Reconciliations. a) Amounts are adjusted for Certain Items. b) Represents DD&A and income tax expense from JVs. 2021 Budget $ 2,109 $ (11) 2020 Actual Change $ % 119 $ 1,990 1672% 1,892 (1,903) (101%) 2,223 2,304 (81) (4%) 574 588 (14) (2%) 419 449 (30) (7%) 1,515 1,610 (95) (6%) $ 6,829 $ 6,962 $ (133) (2%) KINDER MORGAN 35#36GAAP Reconciliations $ in millions 2020 Certain KINDER MORGAN Items in Segment Adjusted Adjusted EBDA Segment Segment Reconciliation of Adjusted Segment EBDA (GAAP) EBDA EBDA Natural Gas Pipelines $3,483 $983 $4,466 Fair value amortization Products Pipelines 977 50 1,027 Certain Items Legal, environmental and taxes other than income tax reserves Terminals CO2 1,045 (55) 990 Change in fair value of derivative contracts (a) (292) 944 652 Loss on divestitures and impairments, net (b) Total $5,213 $1,922 $7,135 Reconciliation of Net Debt Outstanding long-term debt Current portion of debt Foreign exchange impact on hedges for Euro Debt outstanding Less: cash & cash equivalents Net Debt Adjusted EBITDA Net Debt to Adjusted EBITDA 2020 $ 30,838 2,558 (170) (1,184) $ 32,042 $ 6,962 4.6X Loss on impairment of goodwill(c) Restricted stock accelerated vesting and severance COVID-19 costs Income tax Certain Items Other Total Certain Items a) Gains or losses reflected in Certain Items are unrealized. Gains or losses are reflected in our DCF when realized. b) Includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $55 million gain on an asset sale in our Terminals business segment. c) Includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-regulated and CO2 reporting units, respectively. 2020 $ (21) 26 (5) 327 1,600 52 15 (107) 5 $ 1,892 36#37GAAP Reconciliations $ in millions Reconciliation of DD&A and amortization of excess cost of equity investments for DCF Depreciation, depletion and amortization (GAAP) Amortization of excess cost of equity investments (GAAP) DD&A and amortization of excess cost of equity investments JV DD&A DD&A and amortization of excess cost of equity investments for DCF Reconciliation of general and administrative and corporate charges General and administrative (GAAP) Corporate charges Certain Items General and administrative and corporate charges (a (a) Reconciliation of interest, net Interest, net (GAAP) Certain Items Interest, net(a) a) Amounts are adjusted for Certain items. b) Amounts are associated with our Citrus, NGPL and Plantation equity investments. KINDER MORGAN 2020 ($2,164) Reconciliation of income tax expense for DCF Income tax expense (GAAP) (140) Certain Items (2,304) Income tax expense (a) (367) Unconsolidated JV income tax expense (b) ($2,671) Income tax expense for DCF(a) 2020 $ (481) (107) (588) (82) (670) ($648) Reconciliation of additional JV information Unconsolidated JV DD&A $ (407) (5) Less: Consolidated JV partners' DD&A (40) 92 JV DD&A (367) ($561) Unconsolidated JV income tax expense (a,b) (82) JV DD&A and income tax expense (a) $ (449) Unconsolidated JV cash taxes (b) $ (62) (1,595) Unconsolidated JV sustaining capital expenditures $ (120) (15) (1,610) Less: Consolidated JV partners' sustaining capital expenditures (6) JV sustaining capital expenditures $ (114) 37#38Reconciliations of KMI FCF & CO2 Segment FCF $ in millions Reconciliation of KMI FCF CFFO (GAAP) Capital expenditures (GAAP) FCF Dividends paid (a) FCF after dividends Reconciliation of CO2 Segment FCF Segment EBDA Certain items: Non-cash impairments and project write-offs Derivatives and other Severance tax refund Adjusted Segment EBDA Capital expenditures (b) Acquisitions CO₂ Segment FCF a) Includes dividends paid for the preferred shares for the years ended 2016, 2017, and 2018. b) Includes sustaining and expansion capital expenditures. 2016 2017 2018 2019 KINDER MORGAN 2020 $ 4,795 $ 4,601 $ 5,043 $ 4,748 $ 4,550 (2,882) (3,188) (2,904) (2,270) (1,707) 1,913 1,413 2,139 2,478 2,843 (1,272) (1,276) (1,774) (2,163) (2,362) $ 641 $ 137 $ 365 $ 315 $ 481 SA $ 827 847 759 $ 681 (292) 29 29 79 75 950 63 40 90 (49) (6) - (21) 919 (276) $ 643 887 (436) 907 707 652 (397) (349) (186) - (21) $ 451 $ 489 $ 358 $ 466 38