Kinder Morgan, Inc. · NYSE:KMI
Kinder Morgan — Investor Presentation (February 2025)
65 slides from Kinder Morgan's investor presentation, February 2025
Slide 1: 2025 Annual Business Update
2025 Annual Business Update February 2025 Elba LNG Storage Tanks
Slide 2: Disclosure
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 con
Slide 3: Table of Contents
Table of Contents Introduction 4 Delivering Energy, Improving Lives Macro Outlook 12 Strong Fundamentals Supporting Sustainable Growth Business Outlook 18 Operational Excellence & Execution 2025 Budget 30 Another Year of Robust Financial Growth Appendix 43 TransColorado Right-of-Way
Slide 4: Introduction
INTRODUCTION Delivering Energy, Improving Lives EPNG Mojave Compressor Station
Slide 5: Irreplaceable Infrastructure Portfolio
Irreplaceable Infrastructure Portfolio NATURAL GAS Delivering Energy. Improving Lives. Largest U.S. Natural Gas Transmission Network — ~66,000 miles of natural gas pipelines moving ~40% of 65% U.S. natural gas production — Interest in over 700 bcf of working storage capacity, ~15% of U.S. capacity R
Slide 6: Driving Long-Term Shareholder Value
Driving Long-Term Shareholder Value Predictable & Natural Gas Balance Sheet High-Returning Returns to Growing Cash Focus Strength Growth Projects Shareholders Flows ~2/3 of cash flows ~69% of cash flows ~3.8x YE 2025B Net Increasing dividend come from are take-or-pay or Debt / Adjusted for 8th strai
Slide 7: Highly Contracted, Predictable Cash Flows
Highly Contracted, Predictable Cash Flows CASH FLOW MIX 95% Take-or-Pay, Fee-Based, or Hedged Cash Flows Unhedged Hedged 5% 5% Take-or-Pay 64% Entitled to payment regardless of throughput Reservation fee for capacity Fee-Based Fee-Based 26% Fixed fee collected regardless of commodity price Volumetri
Slide 8: Strong Business Mix Continues to Improve
Strong Business Mix Continues to Improve BUSINESS MIX Natural Gas Transmission & Storage Natural Gas G&P CHANGES SINCE 2014 CO2 Refined Products Natural Gas Transmission & 27% Steady 26% Storage increased +16% 9% 19% -10% 6% Natural Gas G&P decreased -5% -5% 11% NATURAL GAS CO2 reduced -10% 59% 43%
Slide 9: Growing Our Project Backlog While Maintaining Discipline on Returns
Growing Our Project Backlog While Maintaining Discipline on Returns PROJECT BACKLOG OVER TIME(a) Expansive footprint creates opportunities $ Billion for differentiated returns Natural Gas Segment Other Segments $8.1 Every project must meet disciplined return Natural gas criteria before being added t
Slide 10: $8.1bn Committed Growth Capital Project Backlog
$8.1bn Committed Growth Capital Project Backlog as of 12/31/2024 ~25% of Backlog Capital in Service During 2025 $ million TOTAL Natural Gas (excluding G&P) $6,724 Mostly for LNG, Power, and LDC demand Other 277 Primarily renewable feedstocks & RNG projects Subtotal $7,001 Contracted, stable cash flo
Slide 11: Positioned for Sustained Growth
Positioned for Sustained Growth 2024 2025 Robust Growth and Shareholder Returns Strong Fundamentals Driving Continued Growth +7% Adj. EPS and +5% Adj. EBITDA +10% Adj. EPS and +4% Adj. EBITDA Strong Earnings Year-Over-Year Growth Budgeted Year-Over-Year Growth Growth Generated $5.6 Billion CFFO and
Slide 12: Macro Outlook
Macro Outlook Strong Fundamentals Supporting Sustainable Growth SNG Rose Hill Compressor Station
Slide 13: Demand for U.S. Natural Gas Projected to Grow
Demand for U.S. Natural Gas Projected to Grow U.S. NATURAL GAS DEMAND bcfd +28 bcfd KMI Wood Mackenzie 135 Demand is forecasted to 130 increase 20 – 28 bcfd by +20 bcfd the end of the decade 125 120 The biggest discrepancy between 2030 forecasts is projected power demand growth 115 KMI WoodMac vs. +
Slide 14: WoodMac Natural Gas Demand Overview: 2024 – 2030
WoodMac Natural Gas Demand Overview: 2024 – 2030 >95% of Demand Growth is Expected to Occur in Texas & Louisiana, Driven by Exports & Industrial 2024 U.S. Demand 110 bcfd Increase in demand by 2030 +20 bcfd LNG Feedgas 1 +14 bcfd of Gulf Coast demand growth Well positioned to grow our deliveries ove
Slide 15: LNG Exports Driving Natural Gas Demand Growth
LNG Exports Driving Natural Gas Demand Growth Growth Primarily Along the Texas & Louisiana Gulf Coast with Great Overlap with Our Assets WOODMAC U.S. LNG FEEDGAS FORECAST bcfd KMI has long-term contracts to move ~7 bcfd to facilities today & ~11 bcfd by the end of 2027 Pursuing ~9 bcfd of additional
Slide 16: Growing Power Needs Boosting Demand for Natural Gas
Growing Power Needs Boosting Demand for Natural Gas INCREASING NATURAL GAS FIRED POWER DEMAND DRIVEN BY Population Migration Coal-to-Gas Industrial Renewable Data Center & Economic Growth Conversions Reshoring Backup Demand KMI forecasting 3 bcfd increase in Increases need for Coal plants continue R
Slide 17: WoodMac Natural Gas Supply Overview: 2024 – 2030
WoodMac Natural Gas Supply Overview: 2024 – 2030 2024 U.S. Production 103 bcfd Increase in supply by 2030 +20 bcfd 4 Permian +8 bcfd of associated gas growth 1 Supply grows as oil production increases & GORs rise 4 Vital to supplying West Coast, Gulf Coast, and Mexico 4 3 Haynesville +6 bcfd of grow
Slide 18: Business Outlook
BUSINESS OUTLOOK Operational Excellence & Execution EPNG McClellan Creek Crossing
Slide 19: Natural Gas Segment Overview
Natural Gas Segment Overview Connecting Key Natural Gas Resources with Major Demand Centers Largest Natural Gas Transmission Network in the U.S. KMI Transports ~40% of U.S. Natural Gas Production ~45% ~50% ~45% of all feedgas of all U.S. natural of all direct natural deliveries to U.S. gas exports t
Slide 20: High-Quality, Natural Gas Focused Cash Flows
High-Quality, Natural Gas Focused Cash Flows G&P 9% Natural Gas Transportation & Storage CASH FLOW MIX(a) – Accounts for 59% of 2025B KMI Adjusted Segment EBDA Remaining KM 35% – 88% take-or-pay cash flows(a) Transportation & Storage – Average remaining contract life: 91% – ~7 years for transportati
Slide 21: Rising Demand Benefitting Our Natural Gas Transportation Business
Rising Demand Benefitting Our Natural Gas Transportation Business INCREASED PIPELINE USAGE FACTOR(a) 2016 5-Pipe 2024 5-Pipe Increased Demand Leading To Average Average WOODMAC U.S. NATURAL GAS DEMAND 74% 87% bcfd +18% INCREASED CONTRACT TERMS AND/OR RATES +38% EXAMPLES 8.1 129.3 7.3 years years 109
Slide 22: ~$7.2 Billion of Approved Natural Gas Projects
~$7.2 Billion of Approved Natural Gas Projects Capital(a) Capacity In-Service Pursuing substantial additional Major Projects ($mm) (bcfd) Date Status opportunities beyond those 1 South System Expansion 4 $1,659 1.2 4Q28, Permitting currently in our backlog SNG & EEC 4Q29 9 Trident 2 $1,650 1.5 1Q27
Slide 23: Products Segment & Terminals Segment Overview
Products Segment & Terminals Segment Overview Both Segments Principally Refined Products Focused Nearly $11bn of Adjusted Segment EBDA & $8bn of FCF Generated Over 5 Years (a) TERMINALS & PRODUCTS PIPELINES ADJUSTED SEGMENT EBDA $ Millions NY Harbor Products Segment Terminals Segment $2,263 $2,282 $
Slide 24: Highly Utilized Products & Terminals Assets
Highly Utilized Products & Terminals Assets Steady Volumes with Annual Rate Escalators (a) PRODUCTS SEGMENT VOLUMES TERMINALS SEGMENT LEASED mbbld CAPACITY PERCENTAGE & TONNAGE +1% ~2.1mmbbld 2025 budgeted -3 % +1 % Flat volumes excluding total throughput impact from Houston 987 983 Refinery closure
Slide 25: Leveraging Our Existing Assets for Renewable Fuels and Feedstocks
Leveraging Our Existing Assets to Meet Growing Demand for Renewable Fuels and Feedstocks PRODUCTS – Ability to throughput combined ~57mbbld of RD at Capacity Northern and Southern California hubs today Truck Rack Storage West Coast RD Assets (mbbld) (mbbl) – >90% subscribed with customer commitments
Slide 26: CO2 Segment: EOR and CO2 Transport Overview
CO2 Segment: EOR and CO2 Transport Overview World Class, Fully-Integrated Assets Consistently Generating Robust Free Cash Flow CO2 EOR & TRANSPORT FREE CASH FLOW Interest in 3 oil CO2 pipelines $ Millions fields with 8.8 CO2 source fields (a) FCF Capex Acquisitions Adj. Segment EBDA Oil fields billi
Slide 27: CO2 Segment: Energy Transition Ventures (ETV) Group Overview
CO2 Segment: Energy Transition Ventures (ETV) Group Overview Pursuing Commercial Opportunities Emerging from the Lower Carbon Energy Evolution Future RNG CCS Opportunities Established a growing RNG platform Evaluating commercial Up to 6.4 bcf(a) of opportunities across the Renewable Fuels, 6 facilit
Slide 28: Committed to Being a Good Steward
Committed to Being a Good Steward $ Reduce & Leak Safety Continuous Diversity & Investing in Lower Avoid Methane Detection Culture Improvement Inclusion Carbon Fuels Emissions ~8% 100% 42% BB → AAA 33% $7.3bn Reduction in Of our natural gas Reduction in MSCI score Total gender Primarily natural gas;
Slide 29: Highly Rated by Sustainability Ratings Agencies
Highly Rated by Sustainability Ratings Agencies Upgrade by MSCI to AAA in 2024 MSCI AAA Sustainalytics Top 15% SSGA Top 10% Oil & Gas Refining, out of 106 Oil & Gas R-Factor in Marketing, Transportation Storage and Transportation Companies & Oil & Gas – Midstream sector & Storage Industry 194 Refine
Slide 30: 2025 Budget
2025 BUDGET Another Year of Robust Financial Growth EPNG Eunice Compressor Station
Slide 31: Capital Allocation Priorities
Capital Allocation Priorities High-Quality and Secure Cash Flows Natural gas focused, long-term, take-or-pay cash flows Balance Sheet Strength Capacity provides value and flexibility Disciplined Capital Allocation Investing in projects well above our cost of capital Significant Free Cash Flow Genera
Slide 32: Growing Earnings While Reducing Leverage and Returning Value to Shareholders
Growing Earnings While Reducing Leverage and Returning Meaningful Value to Shareholders ADJUSTED NET DEBT / DIVIDENDS PAID & EPS ADJUSTED EBITDA SHARES REPURCHASED(b) $ Billion 8% CAGR 28% decrease in $23 billion returned leverage to shareholders $1.32 Uri $1.27 $0.38 $1.16 5.3x $1.15 $0.5 5.1x $0.4
Slide 33: 2025 Budget Highlights
2025 Budget Highlights $ $ Adjusted Adjusted Net Debt / Discretionary Cash EPS EBITDA Adj. EBITDA Capital(a) Returns $1.27 $8.3bn 3.8x $2.3bn $2.6bn ~10% increase ~4% increase -0.2x decrease infrastructure projects dividends expected vs. 2024 vs. 2024 vs. year-end 2024 with attractive returns in 202
Slide 34: Steady Base Business & Growth From Investments
Steady Base Business & Growth From Investments 2024 – 2025B ADJUSTED EBITDA BRIDGE $ Billions $0.0 $0.3 $8.3 $7.9 2024 Base Growth(a) 2025B Adjusted EBITDA Business Projects Adjusted EBITDA Note: Adjusted EBITDA is a non-GAAP financial measure. See Non-GAAP Financial Measures & Reconciliations. Figu
Slide 35: 2025B Adjusted Segment EBDA, Adjusted EBITDA, and Adjusted Net Income
2025B Adjusted Segment EBDA, Adjusted EBITDA, and Adjusted Net Income Attributable to KMI $ in Millions 2025 2024 Change Budget Actual $ % 2025B KEY DRIVERS Natural Gas Pipelines Adjusted Segment EBDA (a) $ 5,636 $ 5,439 $ 197 4% – Contributions from expansion projects Products Pipelines Adjusted Se
Slide 36: 2025B Adjusted EPS
2025B Adjusted EPS $ in Millions, Except Per Share 2025 2024 Change Budget Actual $ % Net income attributable to KMI $ 2,829 $ 2,613 $ 216 8% (a) Total Certain Items 2 (42) 44 105% Adjusted Net Income attributable to KMI 2,831 2,571 260 10% Net income Allocated to participating securities and other
Slide 37: 2025B Discretionary Capital Expenditures
2025B Discretionary Capital Expenditures $ in Millions 2025B KEY PROJECTS 2025 2024 Discretionary Capital Budget Actual Discretionary Capital Natural Gas Pipelines (a) $ 1,854 $ 1,348 – TX Intrastate Trident project Products Pipelines 72 79 – Hiland Express NGL conversion project Terminals 117 108 –
Slide 38: 2025B Cash Flow from Operations & Free Cash Flow
2025B Cash Flow from Operations (CFFO) & Free Cash Flow (FCF) $ in Millions 2025 2024 Change Budget Actual $ % Net income attributable to KMI $ 2,829 $ 2,613 $ 216 8% Net income attributable to noncontrolling interests 106 107 (1) (1%) DD&A 2,411 2,354 57 2% Deferred income taxes 739 647 92 14% Earn
Slide 39: 2025B Sources & Uses
2025B Sources & Uses(a) $ in Millions SOURCES & USES 2025 $ Billions Sources Budget $8.0 CFFO (GAAP) $ 5,899 Other Uses Other Sources Revolver Borrowing/Debt Issuances 1,377 $7.0 Distributions from equity investments in CFFI(b) 411 Additional Borrowing Debt maturities Total sources $ 7,687 $6.0 2025
Slide 40: 2025B Leverage & Liquidity
2025B Leverage & Liquidity(a) $ in Millions 2025 KMI LONG-TERM DEBT MATURITIES(e) Budget Debt maturities Weighted average interest rate Net Debt (Year End) $ 31,408 Adjusted EBITDA $ 8,284 5.5% Net Debt(b) to Adjusted EBITDA 3.8x(c) 5.0% 5.0% 4.3% 3.9% KMI revolver capacity 12/31/2024 3.7% Committed
Slide 41: 2025B Quarterly Profile
2025B Quarterly Profile ADJUSTED EBITDA ADJUSTED EPS $ Billions 2025 Budget 2024 Actuals 2025 Budget 2024 Actuals $2.22 $2.17 $2.14 $2.06 $1.97 $1.92 $0.37 $1.88 $1.86 $0.35 $0.34 $0.32 $0.28 $0.26 $0.25 $0.25 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Note: Adjusted EBITDA and Adjusted EPS are non-GAAP financial meas
Slide 42: Cash Taxes: Do Not Expect to Be a Material Cash Taxpayer Until 2026
Cash Taxes: Do Not Expect to Be a Material Cash Taxpayer Until 2026 KMI PROJECTED EFFECTIVE FEDERAL CASH TAX RATE 20% Do not expect KMI to be a material federal income taxpayer in 2025 15% $312 million of General Business Credits(a), limited to offsetting up to 75% of our annual tax liability 10% 10
Slide 43: Appendix
APPENDIX Liberty RNG Facility
Slide 44: Contract Strategy Insulates Cash Flows Through Commodity Cycles
Contract Strategy Insulates Cash Flows Through Commodity Cycles Structure Long-Term Contracts That Minimize Price & Volume Volatility Take-or-Pay or Hedged Fee-Based Commodity- Avg. remaining Volumes & price are Price is fixed, contract term contractually fixed volumes are variable Price Based as of
Slide 45: 2025 Budget Sensitivities
2025 Budget Sensitivities Limited Overall Commodity Exposure 2025B Assumptions Change Potential Impact to Adjusted EBITDA (Full Year) Natural Gas Products Terminals CO2 Total Natural gas G&P volumes 4,125 bbtud +/- 5% $32.8 million $32.8 million Crude oil & NGL production volumes 34 mbbld net +/- 5%
Slide 46: 2025B Sustaining Capital Expenditures
2025B Sustaining Capital Expenditures $ in Millions 2025B KEY DRIVERS 2025 2024 Sustaining Capital Budget Actual Change Sustaining Capital Natural Gas Pipelines (a) $ 623 $ 703 $ (80) – Fewer compressor repairs Products Pipelines 171 172 (1) Natural Gas – Less regulatory compliance work Terminals 24
Slide 47: Customers Are Primarily End-Users of the Products We Handle
Customers Are Primarily End-Users of the Products We Handle Net Revenues Underpinned by Investment Grade Counterparties & Credit Support | Ratings as of January 10, 2025 CUSTOMER TYPE CREDIT RATING End-user IG or substantial credit support Producer - IG or substantial credit support BB+ to B Produce
Slide 48: Natural Gas Projects Placed Into Service During 2024
Natural Gas Projects Placed Into Service During 2024 IN-SERVICE DATE: 2024 CAPACITY KM SHARE ASSET PROJECT Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (mDthd) CAPITAL ($mm) Evangeline Pass Phase I 900 $283 Port Sulphur Dispatch 235 70 TGP Sunnyside Lackawanna 40 18 Heidelberg 50 8 Texas Central
Slide 49: ~$7.2 Billion Natural Gas Project Backlog
~$7.2 Billion Natural Gas Project Backlog KM SHARE CAPACITY ASSET PROJECT CAPITAL ($mm) (mdTHD) IN-SERVICE DATE PROJECT STATUS Mississippi Crossing $1,637 2,100 4Q28 Permitting Evangeline Pass Project 293 1,100 3Q25 Under construction Cumberland Project 222 245 3Q25(a) Permitting TGP Sta. 40 78 200
Slide 50: Tankers Meeting Domestic Maritime Demand
Tankers Meeting Domestic Maritime Demand Largest Jones Act Tanker Fleet and Most Efficient Vessels American Petroleum Tankers (c) Firm Charter Renewal Option – 16 fuel-efficient Jones Act tankers YE-24 2025 YE-25 2026 YE-26 2027 YE-27 – Largest fleet with the most modern vessels; average age of 10.8
Slide 51: CO2 EOR & Transport Budget and Sensitivities
CO2 EOR & Transport Budget and Sensitivities Potential Impact to SACROC Other EOR CO2 & Transport Adj. EBITDA 2025B Assumptions Change (full year) $320 Crude oil & NGL production +/- 5% in net volumes $35.5 million 34 mbbld net CO2 sales $223 +/- 5% mmcfd in net volumes $5.7 million 329 mmcfd net $1
Slide 52: CO2 Segment Budgeted Volumes & Highlights
CO2 Segment Budgeted Volumes & Highlights 2025B NET OIL & NGL PRODUCTION 2025B NET CO2 SALES mbbld mmcfd McElroy 1.1 Yates 5.9 SACROC 141 34.1 mbbld SACROC Oil Third parties 171 329 mmcfd 18.7 SACROC NGL 8.5 Yates 17 Oil & Gas CO2 & Transport — Majority of required takeaway capacity provided by KMI-
Slide 53: Joint Venture Treatment in Key Metrics
Joint Venture Treatment in Key Metrics KM does not control nor consolidate KM controls & fully consolidates KM portion referred to as equity investments in Third party portion referred to as noncontrolling interests in financial statements financial statements SNG (50%), NGPL (37.5%), GCX (34%) Exam
Slide 54: Non-GAAP Financial Measures & Reconciliations
NON-GAAP FINANCIAL MEASURES & RECONCILIATIONS Altamont Ravolla Compressor Station
Slide 55: Use of Non-GAAP Financial Measures
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 meas
Slide 56: Use of Non-GAAP Financial Measures (Continued)
Use of Non-GAAP Financial Measures (Continued) 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” a
Slide 57: Net Income, Adjusted Net Income Attributable to KMI, and DCF
Net Income, Adjusted Net Income Attributable to KMI, and DCF $ in millions 2025 2024 Change Budget Actual $ % Net income attributable to KMI $ 2,829 $ 2,613 $ 216 8% Certain Items Change in fair value of derivative contracts - 72 (72) (100%) Loss on impairment - (69) 69 100% Income tax Certain Items
Slide 58: 2014 and 2025B Reconciliation of Segment EBDA to Adjusted Segment EBDA
2014 and 2025B Reconciliation of Segment EBDA to Adjusted Segment EBDA $ in millions 2025 2014 2025 2014 (a) (a) Segment EBDA Budget Actual Segment EBDA Budget Actual Natural Gas Pipelines Segment EBDA $ 5,636 $ 4,288 CO2 Segment EBDA 755 1,248 Certain Items (b) Certain Items (b) Contract early term
Slide 59: 2024 Reconciliation of Recasted Adjusted Segment EBDA
2024 Reconciliation of Recasted Adjusted Segment EBDA $ in millions 2024 2024 (a) (b) Segment EBDA Actual Adjustment Recasted Natural Gas Pipelines Segment EBDA $ 5,427 $ (34) $ 5,393 Certain Items (c) - Change in fair value of derivative contracts 75 - 75 Loss on impairments, divestitures and other
Slide 60: Reconciliation of Adjusted Net Income Attributable to Common Stock and Adjusted EPS
Reconciliation of Adjusted Net Income Attributable to Common Stock and Adjusted EPS $ in millions 2016 2017 2018 2019 2020 2021 2022 2023 2024 Net income attributable to KMI $ 708 $ 183 $ 1,609 $ 2,190 $ 119 $ 1,784 $ 2,548 $ 2,391 $ 2,613 NCI associated with Certain Items (8) - - - - - - - - Certai
Slide 61: Reconciliations of KMI FCF and CO2 EOR & Transport FCF
Reconciliations of KMI FCF and CO2 EOR & Transport FCF $ in millions Reconciliation of KMI FCF 2020 2021 2022 2023 2024 2025B CFFO (GAAP) $ 4,550 $ 5,708 $ 4,967 $ 6,491 $ 5,635 $ 5,899 Capital expenditures (GAAP)(a) (1,707) (1,281) (1,621) (2,317) (2,629) (3,141) FCF 2,843 4,427 3,346 4,174 3,006 2
Slide 62: Reconciliations of Terminals FCF and Products Pipelines FCF
Reconciliations of Terminals FCF and Products Pipelines FCF $ in millions Reconciliation of Terminals FCF 2020 2021 2022 2023 2024 2025B EBDA for Terminals (b) $ 1,045 $ 908 $ 975 $ 1,039 $ 1,099 $ 1,103 Certain items: Loss (gain) on impairments, divestitures and other write-downs, net (55) 34 - - -
Slide 63: Reconciliation of Adjusted EBITDA, Normalized for Divestitures
Reconciliation of Adjusted EBITDA, Normalized for Divestitures $ in millions Reconciliation of Adjusted EBITDA, Normalized for Divestitures 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025B Net income attributable to KMI $ 708 $ 183 $ 1,609 $ 2,190 $ 119 $ 1,784 $ 2,548 $ 2,391 $ 2,613 $ 2,829 NCI
Slide 64: Reconciliation of Net Debt
Reconciliation of Net Debt $ in millions Reconciliation of Net Debt 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025B Current portion of debt $ 2,696 $ 2,828 $ 3,388 $ 2,377 $ 2,558 $ 2,646 $ 3,385 $ 4,049 $ 2,009 $ 1,209 Total long-term debt 37,354 35,015 33,936 31,915 32,131 30,674 28,403 28,067
Slide 65: Reconciliation of Adjusted Net Income Attributable to KMI Excluding Uri
Reconciliation of Adjusted Net Income Attributable to KMI Excluding Uri $ in millions 2021 2021 Actual Reconciliation of Adjusted Net income attributable to KM Actual Excluding Uri Net income attributable to KMI $ 1,784 $ 932 Certain Items Fair value amortization (19) (19) Legal, environmental and o
Kinder Morgan — Investor Presentation (February 2025) on 6ix