2 Safe Harbor Statement New slide This presentation contains statements which, to the extent they are not statements of historical or present fact, constitute “forward-looking statements” under the securities laws. These forward-looking statements are intended to provide management’s current expectations or plans for our future operating and financial performance, business prospects, outcomes of regulatory proceedings, market conditions, and other matters, based on what we believe to be reasonable assumptions and on information currently available to us. Forward-looking statements can be identified by the use of words such as “believe,” “expect,” “expectations,” “plans,” “strategy,” “prospects,” “estimate,” “project,” “target,” “anticipate,” “will,” “should,” “see,” “guidance,” “outlook,” “confident,” “may,” and other words of similar meaning. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. In particular, express or implied statements relating to future earnings, cash flow, results of operations, uses of cash, tax rates and other measures of financial performance, future actions, conditions or events, potential future plans, strategies or transactions of DT Midstream, and other statements that are not historical facts, are forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks, and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated, or budgeted. Many factors may impact forward-looking statements of DT Midstream including, but not limited to, the following: changes in general economic conditions, including increases in interest rates and associated Federal Reserve policies, a potential economic recession, and the impact of inflation on our business; industry changes, including the impact of consolidations, alternative energy sources, technological advances, infrastructure constraints and changes in competition; changes in global trade policies and tariffs; global and domestic supply chain disruptions; actions taken by third-party operators, producers, processors, transporters and gatherers; changes in expected production from Expand Energy and other third parties in our areas of operation; demand for natural gas gathering, transmission, storage, transportation, sand mining, and water services; the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels; our ability to successfully and timely implement our business plan; our ability to complete organic growth projects on time and on budget; our ability to finance, complete, or successfully integrate acquisitions; our ability to realize the anticipated benefits of the Midwest Pipeline Acquisition and our ability to manage the risks of the Midwest Pipeline Acquisition; the price and availability of debt and equity financing; restrictions in our existing and any future credit facilities and indentures; the effectiveness of our information technology and operational technology systems and practices to detect and defend against evolving cyber attacks on United States critical infrastructure; changing laws regarding cybersecurity and data privacy, and any cybersecurity threat or event; operating hazards, environmental risks, and other risks incidental to gathering, storing and transporting natural gas; geologic and reservoir risks and considerations; natural disasters, adverse weather conditions, casualty losses and other matters beyond our control; the impact of outbreaks of illnesses, epidemics and pandemics, and any related economic effects; the impacts of geopolitical events, including the conflicts/tensions in Venezuela, Ukraine and the Middle East; labor relations and markets, including the ability to attract, hire and retain key employee and contract personnel; large customer defaults; changes in tax status, as well as changes in tax rates and regulations; the effects and associated cost of compliance with existing and future laws and governmental regulations, such as the Inflation Reduction Act and the One Big Beautiful Bill Act; changes in environmental laws, regulations or enforcement policies, including laws and regulations relating to pipeline safety, climate change and greenhouse gas emissions; changes in laws and regulations or enforcement policies, including those relating to construction and operation of new interstate gas pipelines, ratemaking to which our pipelines may be subject, or other non-environmental laws and regulations; our ability to qualify for federal income tax credits; ability to develop low carbon business opportunities and deploy greenhouse gas reducing technologies; changes in insurance markets impacting costs and the level and types of coverage available; the timing and extent of changes in commodity prices; the success of our risk management strategies; the suspension, reduction or termination of our customers’ obligations under our commercial agreements; disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent; the effects of future litigation; and the risks described in our Annual Report on Form 10-K for the year ended December 31, 2025 and our reports and registration statements filed from time to time with the SEC. The above list of factors is not exhaustive. New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause actual results to vary materially from those stated in forward-looking statements, see the discussion under the section entitled “Risk Factors” in our Annual Report for the year ended December 31, 2025, filed with the SEC on Form 10-K and any other reports filed with the SEC. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, you should not put undue reliance on any forward-looking statements. Any forward-looking statements speak only as of the date on which such statements are made. We are under no obligation to, and expressly disclaim any obligation to, update or alter our forward-looking statements, whether as a result of new information, subsequent events or otherwise.

Leading Organic Growth $3.4B project backlog DTM Provides a Distinctive Investment Opportunity Premium, high-quality, pure play natural gas attributes compared to peers High-Quality Portfolio Mix ~70% Pipeline segment Premier Geographic Presence Growing power and LNG demand Durable Contracting ~95% demand-based contracts1, ~8-year average2 contract tenor Represents % of 2025 revenue contribution comprised of demand, Minimum Volume Commitments (MVCs) or flowing gas/proved developed producing reserves Overall portfolio weighted average contract tenor as of 12/31/2025 DTM 2025 dividend based on annualized Q1 2025 Board-approved dividend ($0.82/share); DTM 2021-2025 Adjusted EBITDA CAGR based on 2021 original guidance to 2025 actual Peer average of gas-focused peers (WMB, KMI, AM, TRP, ENB) Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix Represents 2025 Pipeline and Gathering segment Adjusted EBITDA contributions Peer average includes WMB, KMI, TRP, ENB; Source: Peer company filings as of 2/13/2026 Investment Grade 2.9x on-balance sheet / 3.5x proportional 2026E YE leverage DTM3 Gas-Focused Peers 4 8% 2% Adjusted EBITDA5 CAGR 2021-2025 Dividend CAGR 2021-2025 Differentiated Business Mix and Backlog Business Mix as % of 2025 EBITDA6 Pipeline Gathering 70% 3 30% Peer-leading Dividend and Adjusted EBITDA Growth DTM Peer Average7 300% 260% Project Backlog as % of 2025 EBITDA DTM3 Gas-Focused Peers 4 12% 6% Backlog 75% Pipeline Projects

4 2025 Year in Review Continuing our track record of best-in-class execution Exceeded Adjusted EBITDA Guidance Integrated Midwest Pipelines LEAP Phase 4 Expansion In-service Early Record High Gathering Volumes Achieved Investment Grade

Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix Definition and reconciliation of Distributable Cash Flow (non-GAAP) to net income included in the appendix Represents annualized dividend per share growth from 2024 to 2025 Represents Distributable Cash Flow divided by annualized approved quarterly dividend. Definition and reconciliation of Distributable Cash Flow (non-GAAP) to net income included in the appendix 5 2025 Year in Review: Financial Results Strong financial performance across all key metrics Adjusted EBITDA and Cash Flow $1.138 billion 2025 Adjusted EBITDA1 17% YoY Growth Investments 80% Pipeline projects Return of Capital 12% YoY dividend growth3 ~2.6x Dividend coverage ratio4 >$1 billion Organic opportunities advanced from project backlog $831 million 2025 Distributable Cash Flow2 14% YoY Investment Grade With all three major credit rating agencies 3.0x / 3.7x 2025 YE on-balance sheet / proportionate leverage Balance Sheet

Assumes dividend reinvestment; from 7/1/2021 to 2/11/2026 6 Strategic Accomplishments Since Spin Disciplined execution of focused strategy delivers exceptional results Increase pipeline segment  Jul 2021 Dec 2025 Dec 2022 Dec 2024 Dec 2023 Dec 2021 Diversify customer base  Achieve Investment Grade  Grow dividend  Maintain contract tenor  07/01/2021 DT Midstream Spin $38.65 Opening Trade ~280% Total Shareholder Return1 $20 $40 $60 $80 $100 $120 $140 DTM AMNA S&P 500 DTM Increase size and scale  $/share

2021 original guidance 2021 2022 2023 2024 2025 +12% CAGR Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix DTM Adjusted EBITDA growth from 2021 original guidance at spin-off through 2025 actual Peer average growth of gas focused peers (WMB, KMI, AM, TRP, ENB) from 2021 actual Adjusted EBITDA 7 Delivering High-Quality Growth Strong, durable growth with a proven track record Historical Adjusted EBITDA1 (millions) Well positioned assets and take-or-pay contract structures consistently deliver best-in-class results  Gas-focused peers3 12% 6% Relative Growth vs. Peers 2021-2025 Adjusted EBITDA CAGR2

Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix 8 Full Year 2025 Financial Results 27% growth in the pipeline segment 2024 2025 $969 $1,138 +17% Pipeline Gathering Pipeline Midwest Pipeline Acquisition, higher LEAP and W10 storage revenue Gathering Record high volumes on Blue Union and Tioga, partially offset by lower volumes on Susquehanna and Appalachia ~27% ~1% Adjusted EBITDA1 (millions) Year-over-Year Growth

75% Pipeline 20% Gathering 9 Capital Project Backlog Opportunities Expand to ~$3.4 billion 50% increase, highly concentrated in pipeline projects Pipeline Project Contribution Status Midwestern Gas Transmission power plant lateral Q1 2026 Under construction Millennium R2R Q1 2027 Precedent agreement Phase 1 & 2 Interstate Pipelines Modernization 2H 2027 / 1H 2028 Under construction Viking Gas Transmission expansion Q4 2027 Under construction Guardian Pipeline “G3” expansion Q4 2028 Under construction Vector pipeline expansion 2028 Precedent agreement Stonewall/Appalachia Gathering power plant lateral 2030 Precedent agreement NEXUS interconnections / laterals 2027-30 Pre-FID3 Interstate pipelines expansions 2028-30 Pre-FID Haynesville System (LEAP) expansions 2028-30 Pre-FID Storage development/expansion 2028-30 Pre-FID Interstate pipelines power plant laterals 2027-30 Pre-FID Modernization of interstate assets 2029-30 Pre-FID Gathering Project Contribution Status Blue Union Gathering well pad expansions & buildout 2027-28 Pre-FID Ohio Utica Gathering buildout 2027-28 Pre-FID Tioga Gathering buildout 2028-29 Pre-FID Appalachia Gathering System expansions 2027-30 Pre-FID Backlog Project Composition Probability-adjusted Pre-FID Louisiana CCS Project Final investment decision 2025-2029 2026-2030 ~50% DTM Organic Project Backlog1, $B Projects at 5-8x build multiples

Elevated Organic Growth At end of decade Differentiated growth drivers Investments focused in core natural gas pipeline assets Backed by long-term contracts with investment grade customers FERC-pipeline investments provide higher growth toward end of decade Strong cash flows and healthy balance sheet fully fund growth plan, with headroom for additional opportunities Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix 10 Entering a Period of Generational Investment Opportunities Sizeable organic project backlog supports Adjusted EBITDA growth above long-term growth rate at the end of decade 2025 original guidance 2026 guidance 2027 early outlook 2030 $1,095 - $1,155 $1,155 - $1,225 $1,225 -$1,295 Adjusted EBITDA1 (millions) 5-7% Structural long-term growth rate

2021 2022 2023 2024 2025 20261 +7.3% 8% CAGR Annualized Q1 2026 board approved dividend ($0.88/share) The dividend coverage ratio represents Distributable Cash Flow divided by annualized approved quarterly dividend. Definition and reconciliation of Distributable Cash Flow (non-GAAP) to net income included in the appendix Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix 11 Distinctive Dividend Growth Consistent, secure dividend supported by growing Adjusted EBITDA Annualized dividend (per share) Financial policy is to provide a growing and durable dividend Strong 2025 dividend coverage ratio2 of ~2.6x Plan to continue to grow dividend in-line with Adjusted EBITDA3 Maintain a dividend coverage ratio2 above our 2.0x floor

Viking Pipeline Expansion 15 MMcf/d expansion of lateral serves load growth in Grand Forks, North Dakota Anchored by investment grade utility customer under a long-term, negotiated rate contract Q4 2027 expected in-service Vector Pipeline Expansion ~400 MMcf/d westbound capacity increase into Chicago Successful binding open season closed in January 2026 Q4 2028 expected in-service Phase 2 Interstate Pipeline Modernization Focused on Midwestern Pipeline Improves reliability of capacity serving market corridor between Chicago and Nashville 1H 2028 expected in-service Millennium R2R Project Scaled to meet market need Executed contracts totaling 70 MMcf/d under negotiated rates with two utilities and a power plant Q1 2027 expected full in-service Final investment decision 12 Executing New Pipeline Growth Investments Serving key demand markets Reached FID1 Advancing towards FID  

2026 guidance 2027 $420 - $480 1. See appendix for committed growth capex walk 13 2026 Capital Plan is Largely Committed and 2027 is Advancing Continued commercialization and execution of growth projects from our backlog Growth capex (millions) Organic, demand-driven, capital investments Increasing committed capital to reflect new projects reaching FID Total committed investments of ~$820 million over 2026 and 2027 ~$1.6 billion1 of projects have reached FID through 2030 Committed New Commitments Pre-FID ~$390 Committed

Source: Gas Daily; Price Hubs: Transco Zone 6 NY, Texas Eastern Zone M-2, Northern Ventura, Mich Con, Iroquois Zone 2, Emerson Viking, Chicago, Dawn Ontario, Tennessee Zone 1 14 Strong market signals support the need for new capacity Peak prices and record utilization this winter creates an opportunity for our pipelines Record high utilization across multiple assets this winter All-time record withdrawals from our gas storage complex Peak day flows across Interstate Pipelines Customers with transport capacity were able to access more affordable supply January 2026 Peak Gas Prices for Select Hubs ($/MMBtu) 1/13 1/14 1/15 1/16 1/17 1/18 1/19 1/20 1/21 1/22 1/23 1/24 1/25 1/26 1/27 1/28 1/29 1/30 1/31 2/1 2/2 2/3 2/4 2/5 2/6 2/7 2/8 2/9 2/10 2/11 2/12 Chicago Ontario Emerson New England Michigan Twin Cities Appalachia New York Tennessee Twin Cities $70.94 Chicago $65.65 Michigan $63.00 Ontario $69.67 Emerson $20.41 New England $179.17 New York $142.81 Tennessee $56.99 Appalachia $52.45

Includes Illinois, Indiana, Kentucky, Michigan, Minnesota, Ohio, Tennessee and Wisconsin Assumes 1 GW = 0.15 Bcf/d of natural gas Source: S&P Global Commodity Insights North American Power Market Outlook, December 2025 15 Strategically Located Assets to Serve Power Demand Growth Coal retirements will drive growth in natural gas demand 35 GW summer capacity Forecasted Coal Plant Retirements1 2026-2040 +5 Bcf/d Potential Natural Gas Demand2

Assumes 1 GW = 0.15 Bcf/d natural gas demand Midcontinent Independent System Operator, Inc. PJM Interconnection LLC, RTO Region Source: Utility company announcements, S&P Global Commodity Insights North American Power Market Outlook, December 2025 16 Extensive Interstate Network Adjacent to Growing Utility Demand Data center opportunities accelerating Upper Midwest natural gas demand 16 GW 11 GW 12 GW Utility Announced Data Center & Large Load Opportunities 10 GW ~50 GW Utility Announced Opportunities ~7.5 Bcf/d Natural Gas Demand1 Forecasted Total Annual Power Demand (TWh) 2025 2030 +16% 2025 2030 +15% MISO2 PJM3

Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix Definition and reconciliation of Operating Earnings and Operating Earnings per Share (non-GAAP) to reported earnings included in the appendix; EPS calculation based on average share count of approximately 103 million shares outstanding - diluted Definition and reconciliation of Distributable Cash Flow (non-GAAP) to net income included in the appendix Includes contribution to equity method investees 17 2026/2027 Guidance Summary (millions, except EPS) Guidance 2026 Adjusted EBITDA1 $1,155 - $1,225 2026 Operating Earnings2 $455 - $495 2026 Operating EPS2 $4.42 - $4.82 2026 Distributable Cash Flow3 $830 - $890 2026 Capital Investment4 $490 - $570 Growth Capital $420 - $480 Maintenance Capital $70 - $90 2027 Adjusted EBITDA (early outlook) $1,225 - $1,295

18 Appendix

Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in this appendix Definition and reconciliation of Operating Earnings and Operating Earnings per Share (non-GAAP) to reported earnings included in the appendix; EPS calculation based on average share count of approximately 103 million shares outstanding – diluted for 2025 and approximately 98 million shares outstanding – diluted for 2024 Definition and reconciliation of Distributable Cash Flow (non-GAAP) to net income included in this appendix Includes contribution to equity method investees 2024 growth capital reflects total DT Midstream capital spend of $320 million less contributions from customers of $19 million plus $1.2 billion related to the Midwest Pipeline Acquisition 2025 growth capital reflects total DT Midstream capital spend of $369 million less contributions from customers of $17 million 19 Full-Year Financial Results (millions, except EPS) 2024 2025 Change Adjusted EBITDA1 $969 $1,138 17% Pipeline segment $621 $786 27% Gathering segment $348 $352 1% Operating Earnings2 $375 $441 18% Operating EPS2 $3.81 $4.30 13% Distributable Cash Flow3 $727 $831 14% Growth Capital4 $1,5015 $3526 Maintenance Capital $30 $62

Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in the appendix Definition and reconciliation of Operating Earnings and Operating Earnings per Share (non-GAAP) to reported earnings included in the appendix; EPS calculation based on average share count of approximately 103 million shares outstanding – diluted on December 31, 2025 and September 30, 2025 Definition and reconciliation of Distributable Cash Flow (non-GAAP) included in the appendix Includes contribution to equity method investees Growth capital reflects DT Midstream capital spend of $110 million less $7 million contribution from customers received in Q4 2025 Growth capital reflects DT Midstream capital spend of $119 million less $4 million contribution from customers received in Q3 2025 20 Quarterly Financial Results Three months ended (millions, except EPS) December 31, 2025 September 30, 2025 Key drivers Adjusted EBITDA1 $293 $288 Pipeline segment $200 $195 Higher revenue on pipeline joint ventures and LEAP Gathering segment $93 $93 Higher revenue due to higher volumes offset by higher maintenance Operating Earnings2 $111 $115 Operating EPS2 $1.08 $1.13 Distributable Cash Flow3 $162 $262 Cash interest expense in Q4 Growth Capital4 $1035 $1156 Maintenance Capital $29 $19

21 Gathering Volume Summary Record high total Haynesville and Northeast gathered volumes in Q4 Q4 2024 Q1 2025 Q2 2025 Q3 2025 Q4 2025 +34% Haynesville throughput (bcf/d) Q4 2024 Q1 2025 Q2 2025 Q3 2025 Q4 2025 1.37 1.30 1.17 1.09 1.28 Northeast throughput (bcf/d) Appalachia Gathering Susquehanna Gathering Tioga Gathering Ohio Utica Gathering Blue Union Gathering February 2026 month-to-date volume average is ~2 Bcf/day

1. Definition and reconciliation of Adjusted EBITDA (non-GAAP) to net income included in this appendix 22 Diversified Asset Base Anchored by Regulated Pipelines Pipeline segment increased to 70% of the business in 2025 2025 Business Mix LEAP 14% Millennium 10% NEXUS 9% Stonewall 8% Guardian 5% W10 Storage 6% Bluestone 5% Viking 4% 4% Midwestern Vector 3% Michigan 1% Birdsboro <1% Blue Union 13% AGS 8% Susquehanna 7% 2% Tioga OH Utica <1% (% of total 2025 Adjusted EBITDA2) Highly contracted asset portfolio supports stable cash flows Pipeline assets contracted long-term with take-or-pay contracts Gathering assets contracted long-term significant minimum volume commitments (MVCs) Acreage dedications Rate escalators tied to inflation Gathering 30% Pipeline 70%

23 Committed Growth Capex ~50% of $3.4 billion organic project backlog committed Committed capital represents expected investment for all in progress projects not yet in-service 2025-2029 Committed growth capex (Q3 2025 disclosure) -$0.3 2025 Capex placed in-service 2025 Capex not yet in-service 2026-2030 New committed growth capex (Q4 2025 disclosure) Total Committed growth capex ~$1.6 ~$0.2 ~$0.1 ~$1.6 Growth capex (billions)

Growth Investment Projects in Progress Continuing track record of completing growth investments early and on budget In progress project updates Stonewall to MVP and Appalachia Phase 3 expansions completed ahead of schedule and on budget Reached FID for Viking Pipeline expansion and Phase 2 of Interstate Pipelines Modernization Project1 Expected in-service dates Pipeline Stonewall to Mountain Valley Pipeline (MVP) expansion In-Service Midwestern Gas Transmission power plant lateral Q1 2026 Phase 1 Interstate Pipelines Modernization 2H 2027 Viking Pipeline expansion – New Q4 2027 Phase 2 Interstate Pipelines Modernization - New 1H 2028 Guardian Pipeline “G3” expansion Q4 2028 Gathering Appalachia Gathering System expansion – Phase 3 In-Service 24 1. All projects listed have reached a final investment decision

Represents dates by which pipelines must file rate cases 25 Phase 2 of Modernization on Interstate Pipelines Reaches FID Continuing investment in modernization projects to enhance system efficiency and reliability Second phase predominantly focused on Midwestern Pipeline Modernization enhancements will improve system efficiency and reliability for customers 1H 2028 expected in-service date Capital investment of $140 to $160 million will be recovered in next rate case Additional modernization opportunities Projects improve reliability and service quality for customers Investments will be recovered in future rate cases Rate Case Filing Timelines1 Guardian Pipeline Midwestern Gas Transmission Viking Gas Transmission 2H 2026 2H 2027 2H 2028

Includes Allowance for Funds Used During Construction (AFUDC) 26 Executing on “G3” Guardian Pipeline Expansion Preparing for FERC application filing Map Update In Progress “G3” expansion increases delivery capacity into upper Midwest markets ~537 MMcf/d total expansion with expected Q4 2028 in-service date Expansion will be completed via a combination of compression and looping $850 to $930 million total capital investment1 at 5-6x build multiple Anchored by precedent agreements with five investment-grade utilities 20-year contract terms Negotiated rates FERC application submission expected mid-2026 GUARDIAN PIPELINE MIDWESTERN GAS TRANSMISSION VECTOR PIPELINE Joliet ~537 MMcf/d “G3” Expansion

27 LEAP Well Positioned for Future Expansions Haynesville System current capacity of 2.1 Bcf/d, with expansion capability to ~4 Bcf/d LEAP capacity (Bcf/d) LEAP capacity (Bcf/d) In-service Original Phase 1 expansion Aug. 2023 Phase 2 expansion Jan. 2024 Phase 3 expansion Jun. 2024 Phase 4 expansion Sep. 2025 Total Expansion potential 0.3 0.2 0.2 2.1 Integrated Haynesville system provides timely access to coming LNG demand Fully contracted by long-term take-or-pay agreements Competitive advantage through multiple market access at Gillis Hub Adding 1 Bcf/d interconnect to Driftwood Line 200 (Woodside Louisiana LNG) Increasing Cameron interconnect by 0.25 Bcf/d Continuing discussions for additional expansions LEAP can be further expanded to ~4 Bcf/d to serve growing Gulf Coast LNG and industrial corridor demand Timing of future expansions will likely align with next wave of LNG in 2028-2030 timeframe ~4 DTM assets DTM treating plants LNG facilities Electric compression Operational Under development Acreage dedication 2.1 Bcf/d Capacity LNG Corridor

Sources: Wood Mackenzie North America Gas Investment Horizon Outlook – November 2025 28 Strong US Demand and Production Fundamentals Three-fourths of demand growth will be served by Haynesville and Appalachia production U.S. Natural Gas Demand Forecast 2025 2030 49 63 +14 bcf/d Production Forecast – DTM Basins (bcf/d) Haynesville Appalachia 2025 2030 115 134 +19 Bcf/d (bcf/d) ResComm Industrial Power LNG Exports Net Mexican Exports Other

Interconnect provides a pathway to reach majority of terminals within the LNG corridor Source: Wood Mackenzie North America Gas Investment Horizon Outlook – November 2025 29 Leading Competitive Market Position to Serve Growing LNG Demand Competitive advantage from superior connectivity to basin supply and LNG markets 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 +14 Bcf/d Haynesville Supply Forecast (Bcf/d) 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 +12 Bcf/d DTM’s Haynesville System Direct LNG Market Connections (Bcf/d) Sabine Pass Cameron Calcasieu Pass Plaquemines Golden Pass Port Arthur Woodside Louisiana Existing/Future LEAP Interconnect Capacity (Bcf/d) LNG terminal / market Transco 0.5 Industrial / LNG corridor1 Cameron 0.25 Cameron LNG, Port Arthur LNG Creole Trail 1.0 Sabine Pass LNG Texas Eastern 0.75 Calcasieu Pass LNG Targa 0.1 Industrial TC Energy Gillis Access 1.0 Industrial / Plaquemines LNG, Calcasieu Pass LNG Driftwood Line 200 (Future) 1.0 Louisiana LNG Cameron Expansion (Future) 0.25 Cameron LNG, Port Arthur LNG ~4.9 Bcf/d Downstream Interconnectivity1 ~3.5 Bcf/d Receipt Capacity

Weighted average interest rate on debt instruments as of December 31, 2025 Inclusive of capital lease interest expense 30 Joint Venture Debt Details Annual debt paydown at Millennium and Vector DTM proportionate share End of year debt balances Interest expense Asset (DTM ownership %) 2025 2026 2027 2025 2026 2027 Weighted average interest rate1 Maturity NEXUS Pipeline (50%) $375 $375 $375 $21 $21 $21 5.56% Bullets, 2028 through 2035 Millennium Pipeline (52.5%) $114 $99 $83 $9 $7 $6 5.87% Fully amortized by 2032 $420 $420 $420 $25 $25 $25 5.88% Bullets, 2029 through 2036 Total Millennium $534 $519 $503 $34 $32 $31 Vector Pipeline (40%) $26 $25 $25 $22 $22 $22 4.62% 2034 2024 Issuance Prior Issuance ($ values in millions)

31 Non-GAAP Definitions Adjusted EBITDA and Distributable Cash Flow (DCF) are non-GAAP measures New slide Adjusted EBITDA is defined as GAAP net income attributable to DT Midstream before expenses for interest, taxes, depreciation and amortization, and loss from financing activities, further adjusted to include our proportional share of net income from our equity method investees (excluding interest, taxes, depreciation and amortization), and to exclude certain items we consider non-routine. We believe Adjusted EBITDA is useful to us and external users of our financial statements in understanding our operating results and the ongoing performance of our underlying business because it allows our management and investors to have a better understanding of our actual operating performance unaffected by the impact of interest, taxes, depreciation, amortization and non-routine charges noted in the table below. We believe the presentation of Adjusted EBITDA is meaningful to investors because it is frequently used by analysts, investors and other interested parties in our industry to evaluate a company’s operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending on accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors. We use Adjusted EBITDA to assess our performance by reportable segment and as a basis for strategic planning and forecasting. Distributable Cash Flow (DCF) is calculated by deducting earnings from equity method investees, depreciation and amortization attributable to noncontrolling interests, cash interest expense, maintenance capital investment (as defined below), and cash taxes from, and adding interest expense, income tax expense, depreciation and amortization, certain items we consider non-routine and dividends and distributions from equity method investees to, Net Income Attributable to DT Midstream. Maintenance capital investment is defined as the total capital expenditures used to maintain or preserve assets or fulfill contractual obligations that do not generate incremental earnings. We believe DCF is a meaningful performance measurement because it is useful to us and external users of our financial statements in estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and making maintenance capital investments, which could be used for discretionary purposes such as common stock dividends, retirement of debt or expansion capital expenditures. Adjusted EBITDA and DCF are not measures calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for the results of operations presented in accordance with GAAP. There are significant limitations to using Adjusted EBITDA and DCF as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss. Additionally, because Adjusted EBITDA and DCF exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, Adjusted EBITDA and DCF do not intend to represent net income attributable to DT Midstream, the most comparable GAAP measure, as an indicator of operating performance and are not necessarily comparable to similarly titled measures reported by other companies. Reconciliation of net income attributable to DT Midstream to Adjusted EBITDA or DCF as projected for full-year 2026 or 2027 is not provided. We do not forecast net income as we cannot, without unreasonable efforts, estimate or predict with certainty the components of net income. These components, net of tax, may include, but are not limited to, impairments of assets and other charges, divestiture costs, acquisition costs, or changes in accounting principles. All of these components could significantly impact such financial measures. At this time, management is not able to estimate the aggregate impact, if any, of these items on future period reported earnings. Accordingly, we are not able to provide a corresponding GAAP equivalent for Adjusted EBITDA or DCF.

32 Non-GAAP Definitions Operating Earnings and Operating Earnings per share are non-GAAP measures New slide Use of Operating Earnings Information – Operating Earnings exclude non-recurring items, certain mark-to-market adjustments and discontinued operations. DT Midstream management believes that Operating Earnings provide a more meaningful representation of the company’s earnings from ongoing operations and uses Operating Earnings as the primary performance measurement for external communications with analysts and investors. Internally, DT Midstream uses Operating Earnings to measure performance against budget and to report to the Board of Directors. In this presentation, DT Midstream provides guidance for future period Operating Earnings. It is likely that certain items that impact the company’s future period reported results will be excluded from operating results. A reconciliation to the comparable future period reported earnings is not provided because it is not possible to provide a reliable forecast of specific line items (i.e., future non-recurring items, certain mark-to-market adjustments and discontinued operations). These items may fluctuate significantly from period to period and may have a significant impact on reported earnings.

New slide 33 Non-GAAP Reconciliations Reconciliation of Reported to Operating Earnings – DT Midstream Consolidated Three Months Ended December 31, September 30, 2025 2025 Reported Earnings Pre-tax Adjustments Income Taxes (1) Operating Earnings Reported Earnings Pre-tax Adjustments Income Taxes (1) Operating Earnings (millions) Adjustments $ — $ — $ — $ — Net Income Attributable to DT Midstream $ 111 $ — $ — $ 111 $ 115 $ — $ — $ 115 Year Ended December 31, December 31, 2025 2024 Reported Earnings Pre-tax Adjustments Income Taxes (1) Operating Earnings Reported Earnings Pre-tax Adjustments Income Taxes (1) Operating Earnings (millions) Midwest Pipeline Acquisition Tax Impact $ — $ — $ — $ 22 A Louisiana Tax Impact — — — (4) B Bridge Facility — — 4 C (1) Net Income Attributable to DT Midstream $ 441 $ — $ — $ 441 $ 354 $ 4 $ 17 $ 375 (1) Excluding tax related adjustments, the amount of income taxes was calculated based on a combined federal and state income tax rate, considering the applicable jurisdictions of the respective segments and deductibility of specific operating adjustments Adjustments Key A State tax rate increase impact to deferred income tax expense due to Midwest Pipeline Acquisition B State tax rate reduction impact to deferred income tax expense due to enacted tax legislation C Bridge Facility interest expense related to funding Midwest Pipeline Acquisition

Non-GAAP Reconciliations New slide Reconciliation of Reported to Operating Earnings per diluted share(1) – DT Midstream Consolidated 34 Three Months Ended December 31, September 30, 2025 2025 Reported Earnings Pre-tax Adjustments Income Taxes (2) Operating Earnings Reported Earnings Pre-tax Adjustments Income Taxes (2) Operating Earnings (per share) Adjustments $ — $ — $ — $ — Net Income Attributable to DT Midstream $ 1.08 $ — $ — $ 1.08 $ 1.13 $ — $ — $ 1.13 Year Ended December 31, December 31, 2025 2024 Reported Earnings Pre-tax Adjustments Income Taxes (2) Operating Earnings Reported Earnings Pre-tax Adjustments Income Taxes (2) Operating Earnings (per share) Midwest Pipeline Acquisition Tax Impact $ — $ — $ — $ 0.22 A Louisiana Tax Impact — — — (0.04) B Bridge Facility — — 0.04 C (0.01) Net Income Attributable to DT Midstream $ 4.30 $ — $ — $ 4.30 $ 3.60 $ 0.04 $ 0.17 $ 3.81 (1) Per share amounts are divided by Weighted Average Common Shares Outstanding — Diluted, as noted on the Consolidated Statements of Operations (2) Excluding tax related adjustments, the amount of income taxes was calculated based on a combined federal and state income tax rate, considering the applicable jurisdictions of the respective segments and deductibility of specific operating adjustments Adjustments Key A State tax rate increase impact to deferred income tax expense due to Midwest Pipeline Acquisition B State tax rate reduction impact to deferred income tax expense due to enacted tax legislation C Bridge Facility interest expense related to funding Midwest Pipeline Acquisition

35 Reconciliation of Net Income Attributable to DT Midstream to Adjusted EBITDA Non-GAAP Reconciliations Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 Consolidated (millions) Net Income Attributable to DT Midstream $ 111 $ 115 $ 441 $ 354 Plus: Interest expense 41 40 161 153 Plus: Income tax expense 40 35 144 137 Plus: Depreciation and amortization 67 65 258 209 Plus: Loss from financing activities — — — 5 Plus: EBITDA from equity method investees (1) 70 69 276 284 Less: Interest income — (1) (2) (7) Less: Earnings from equity method investees (37) (34) (138) (162) Less: Depreciation and amortization attributable to noncontrolling interests (1) (1) (4) (4) Other 2 — 2 — Adjusted EBITDA $ 293 $ 288 $ 1,138 $ 969 (1) Includes share of our equity method investees’ earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA.” A reconciliation of earnings from equity method investees to EBITDA from equity method investees follows: Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 (millions) Earnings from equity method investees $ 37 $ 34 $ 138 $ 162 Plus: Depreciation and amortization attributable to equity method investees 19 22 82 82 Plus: Interest expense attributable to equity method investees 14 13 56 40 EBITDA from equity method investees $ 70 $ 69 $ 276 $ 284

36 Reconciliation of Net Income Attributable to DT Midstream to Adjusted EBITDA Pipeline Segment Non-GAAP Reconciliations Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 Pipeline (millions) Net Income Attributable to DT Midstream $ 93 $ 92 $ 370 276 Plus: Interest expense 13 14 51 47 Plus: Income tax expense 34 28 121 107 Plus: Depreciation and amortization 28 27 111 74 Plus: Loss from financing activities — — — 3 Plus: EBITDA from equity method investees (1) 70 69 276 284 Less: Interest income — — (1) (4) Less: Earnings from equity method investees (37) (34) (138) (162) Less: Depreciation and amortization attributable to noncontrolling interests (1) (1) (4) (4) Adjusted EBITDA $ 200 $ 195 $ 786 $ 621 (1) Includes share of our equity method investees’ earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA.” A reconciliation of earnings from equity method investees to EBITDA from equity method investees follows: Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 (millions) Earnings from equity method investees $ 37 $ 34 $ 138 $ 162 Plus: Depreciation and amortization attributable to equity method investees 19 22 82 82 Plus: Interest expense attributable to equity method investees 14 13 56 40 EBITDA from equity method investees $ 70 $ 69 $ 276 $ 284

37 Reconciliation of Net Income Attributable to DT Midstream to Adjusted EBITDA Gathering Segment Non-GAAP Reconciliations Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 Gathering (millions) Net Income Attributable to DT Midstream $ 18 $ 23 $ 71 $ 78 Plus: Interest expense 28 26 110 106 Plus: Income tax expense 6 7 23 30 Plus: Depreciation and amortization 39 38 147 135 Plus: Loss from financing activities — — — 2 Less: Interest income — (1) (1) (3) Other 2 — 2 — Adjusted EBITDA $ 93 $ 93 $ 352 $ 348

Non-GAAP Reconciliations 38 Reconciliation of Net Income Attributable to DT Midstream to Distributable Cash Flow Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2025 2025 2025 2024 Consolidated (millions) Net Income Attributable to DT Midstream $ 111 $ 115 $ 441 $ 354 Plus: Interest expense 41 40 161 153 Plus: Income tax expense 40 35 144 137 Plus: Depreciation and amortization 67 65 258 209 Plus: Loss from financing activities — — — 5 Plus: Adjustments for non-routine items (1) — — — (416) Less: Earnings from equity method investees (37) (34) (138) (162) Less: Depreciation and amortization attributable to noncontrolling interests (1) (1) (4) (4) Plus: Dividends and distributions from equity method investees 48 61 187 633 Less: Cash interest expense (76) 1 (151) (140) Less: Cash taxes (2) (1) (5) (12) Less: Maintenance capital investment (2) (29) (19) (62) (30) Distributable Cash Flow $ 162 $ 262 $ 831 $ 727 (1) Distributable Cash Flow calculation excludes certain items we consider non-routine. For the year ended December 31, 2024, adjustments for non-routine items included the $416 million Millennium financing distribution. (2) Maintenance capital investment is defined as the total capital expenditures used to maintain or preserve assets or fulfill contractual obligations that do not generate incremental earnings.