SMC Investor presentation

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Summit Midstream Corporation Investor Presentation August 2026

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Forward-Looking Statements, Legal Disclaimers & Use of Non-GAAP 2 Investors are cautioned that certain statements contained in this presentation are “forward -looking” statements within the meani ng of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amend ed. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will cont inue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any stat ement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward -looking statements in this presentation and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among othe rs: Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cau se a significant reduction in the market price of our common shares, preferred stock and senior notes. You should also consider the factors described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and subsequent Quarterly Reports on Form 10-Q under "Risk Factors", and in other filings with the Securities and Exchange Commi ssion (the "SEC") by the Company, which can be found on the SEC's website at www.sec.gov. The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward -looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law. Investors and others should note that we may announce material information using SEC filings, press releases, public conferen ce calls, webcasts and the Investors page of our website. In the future, we will continue to use these channels to distribute ma terial information about the Company and to communicate important information about the Company, key personnel, corporate initiatives, regulatory updates and other matters. This presentation contains non-GAAP financial measures, such as adjusted EBITDA and distributable cash flow. We report our finan cial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, m anagement believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods. Please see the Appendix for definitions and reconciliation s of the non-GAAP financial measures that are based on reconcilable historical information. ▪ the availability, terms and cost of downstream transportation and processing services; ▪ natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control; ▪ operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water; ▪ our ability to comply with the terms of the agreements related to our settlement of the legal matters related to the release of produced water from a pipeline operated by Meadowlark Midstream Company, LLC in 2015, which is still subject to court approval; ▪ weather conditions and terrain in certain areas in which we operate; ▪ physical and financial risks associated with climate change; ▪ any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating, processing and freshwater facilities; ▪ timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; ▪ our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; ▪ the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; ▪ changes in tax status; ▪ the effects of litigation; ▪ interest rates; ▪ changes in general economic conditions; and ▪ certain factors discussed elsewhere in this presentation. ▪ our decision whether to pay, or our ability to grow, our cash dividends; ▪ fluctuations in natural gas, NGLs and crude oil prices, including as a result of the political or economic measures taken by various countries or OPEC; ▪ the extent and success of our customers' drilling and completion efforts, as well as the quantity of natural gas, crude oil, fresh water deliveries, and produced water volumes produced within proximity of our assets; ▪ the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows; ▪ failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; ▪ competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; ▪ actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; ▪ our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; ▪ the ability to attract and retain key management personnel; ▪ commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets; ▪ changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets; ▪ restrictions placed on us by the agreements governing our debt and preferred equity instruments;

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Piceance Segment Introducing Summit 3 Summit Midstream Corporation (NYSE: SMC) is a value-driven independent natural gas, crude oil and produced water gathering, processing and transmission company with diversified operations across six resource plays in the U.S. (1) Reflects gross margin in 2025: excludes contract amortization, electricity and other pass-throughs / reimbursables. Includes gas retainage revenue which is used to partially offset compression power expense in the Barnett. (2) Represents operated volume throughput for wholly owned assets and includes oil and produced water at a 6:1 conversion ratio. (3) Represents operated volume capacity for wholly owned assets and includes oil and produced water at a 6:1 conversion ratio. (4) Based on the mid-point of 2026E segment adjusted EBITDA guidance. (5) Based on Summit’s closing share price as of 08/26/2026; Includes 13.8 million class A shares and 6.5 million class B shares as of 06/30/2026; Includes $64 million of Series A Preferred; Includes $79 million of ABL borrowings, $825 million of 2029 Second Lien Notes and $350 million of Permian Transmission term loan, net of $21 million of cash and cash equivalents and $10 million of restricted cash >7.0 Weighted Average Contract Life Years ~85% Fixed Fee-Based Gross Margin(1) 1.3 2Q 2026 Total Bcfe/d Volume(2) 69% 2Q 2026 Volumes % Natural Gas 5.9 Total AMI (Acres in Millions) 2,709 Pipeline Miles 4.6 Bcfe/d Capacity(3) Rockies Segment Permian SegmentMid-Con Segment ~50% Exposure to Natural Gas Oriented Drilling Large U.S. Independent Producer 2026E Adj. EBITDA Contribution(4) Franchise positions in crude oil- and natural gas-oriented basinsKey Asset Stats Diversified Key Customer BasePublic Investors 12.4 Million Class A Shares Summit Midstream Corporation (NYSE: SMC) 7.9 Million Class A & B Shares Operating Assets Double E Pipeline, LLC 100% 70% ~61% ~39% Simplified Organization StructureTotal Enterprise Value(5) Common Shares 20.3 (x) Share Price $34.02 Market Capitalization $691 Preferred Equity $64 Sub-Total $755 Net Debt $1,223 Enterprise Value $1,978 ($ in millions, except per share metrics) Arkoma Basin Barnett Shale Permian Basin Piceance Basin DJ Basin Williston Basin 39% 13%12% 36%

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Why Summit, Why Now? 4(1) Based on ~$100 million of expected organic Adjusted EBITDA growth from 2026 to 2030. Attractive Valuation High-Quality Earnings Diversified Footprint Strong Growth Outlook Strong Balance Sheet Scalable InfrastructureOil & Gas Exposure High Free Cash Flow Yield

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Permian & Mid-Con Segments Supporting Natural Gas Demand 5 Summit’s natural gas assets in the Permian and Mid-Con segments are well positioned to support growing natural gas demand from gulf-coast LNG, data center expansion, exports to Mexico and other localized natural gas consumption Source: U.S. Energy Information Administration, Woodmac, company disclosure. Gulf Coast LNG CapacityPipeline Exports to Mexico Mexico Exports Mid-Con Segment Permian Basin Barnett Shale Arkoma Basin Local Demand Local Demand Announced Hyperscale Data Center >15 Bcf/d Growth 6.7 6.9 7.4 7.8 8.4 10.0 10.0 2025 2027 2029 2031 U.S. Pipeline Exports to Mexico (Bcf/d) 3 Bcf/d Growth 13.1 15.7 19.4 20.1 25.6 26.3 28.6 2025 2027 2029 2031 Baseload Nameplate Capacity (Bcf/d) Operational Capacity Under Construction FID

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Double E Pipeline: Critical Permian Natural Gas Infrastructure 6 Double E provides a critical takeaway outlet for growing natural gas production in the Northern Delaware Basin, where limited existing infrastructure has created persistent egress constraints Sources: Enverus (1) Includes the Dude, Big Horn and Kings Landing plants expected to be connected in 2027. (2) Includes recently announced proposed connections to Transwestern Central Pool, Hugh Brinson, and Desert Southwest. AB Pool offers connectivity to Eiger Express, Matterhorn Express, and Whistler. Transwestern Central Pool offers connectivity to Transwestern and NGPL. Key Asset Stats Providing Access to Diversified End Markets 900 2026E Volume (MMcf/d) 135 Pipeline Miles ~1.6 Existing Pipeline Capacity (Bcf/d) ~2.4 Expanded Pipeline Capacity (Bcf/d) >4.0 Connected Plant Capacities (Bcf/d)(1) 10 Downstream Interconnects(2) >15.0 Downstream Pipeline Capacities (Bcf/d)(2) Select Customers JV Parters with 30% Ownership of Double E Other Large Investment Grade Arizona DBLE Facilities Pipeline Receipt Point Delivery Point Central Compression Proposed Lateral 3rd Party Systems Desert SW Trans Pecos GCX | PHP | Eiger Matterhorn | Whistler Transwestern Hugh Brinson NGPL

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1,069 1,211 1,550 1,770 2,164 2,205 2,500+ ~$34 ~$37 ~$53 ~$63 ~$77 ~$80 ~$100+ 2025A 2026E 2027E 2028E 2029E 2030E Fully Contracted Expansion Segment Adjusted EBITDA Contracted Volume (MMBtu/d) Existing Contracts Announced Contracts Expansion Upside Segment Adjusted EBITDA ($MM) Permian Growth Driving Double E Expansion Project (1) “Existing Contracts” represent the MVC quantities that Double E shippers have contracted to with firm transportation service agreements and related negotiated rate agreements. (2) “Announced Contracts” represent the MVC quantities of new precedent agreements for projects not yet placed into service. Commercial Overview Double E Area Map Double E Poised for Significant Growth Rigs New Delivery Point Existing Delivery Point Existing Receipt Point Proposed DBLE Line New Receipt Point Existing DBLE Line Proposed Orla Lateral ➢ Reached FID on the Mainline Compression Expansion, adding ~900 MMcf/d of capacity, with an expected in- service date in the fourth quarter of 2028 ➢ Open season resulted in 550 MMcf/d of new long-term take-or-pay commitments across forward haul and backhaul service ➢ Permian Segment Adjusted EBITDA expected to grow from ~$37 million in 2026 to over $100 million by 2030, assuming the expansion capacity is fully contracted ➢ Summit Permian Transmission term loan and now-committed $50 million accordion expected to fund 100% of Summit's Double E capital contributions 7 (1) (2)

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Double E Compression Expansion Generates Attractive Project Returns with Future Growth Potential Ahead 88 Arizona ➢ Double E has signed ~1.1 Bcf/d of commercial contracts over the last 12 months with an estimated $215 million of 8/8ths project capex and an overall run-rate EBITDA build multiple of ~3.8x(1) ➢ Subscribing the remaining 450 MMcf/d of compression expansion capacity to Waha in the coming months is expected to drive the overall run-rate EBITDA build multiple toward ~3.0x and lifting Permian Segment long-term outlook to ~$100+ million by 2030 ➢ Additionally, the compression expansion creates ~1.0+ Bcf/d of firm backhaul capacity from Waha, which could be contracted to supply emerging demand-pull markets via Double E interconnects, further enhancing the project economics and adding to our long-term outlook. ➢ A future Phase II Compression Expansion could add ~1.3 Bcf/d of forward-haul and ~0.8 Bcf/d of back-haul capacity, which if fully subscribed, could potentially double Summit’s current Permian Segment long-term outlook over the next five years (1) Includes the full capital cost of the Mainline Compression Expansion. Summit’s 70% of the project capex is expected to be funded through the Summit Permian Transmission Term Loan. 0.0 1.0 2.0 3.0 4.0 Free Flow Capacity Mainline Compression Expansion Future Phase II Compression Expansion Forward Haul Capacity Backhaul Capacity Sold to Date % Sold 100% | 58% % Sold 78% | 18% % Sold 51% | 11% Double E Bi-directional Capacity (Bcf/d) DBLE Facilities Pipeline Proposed Lateral 3rd Party Facilities Pipeline Processing Plant Waha Hub

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Rockies Activity Shifting Toward Summit Infrastructure DJ Basin Williston Basin 9Sources: Enverus, Colorado Oil and Gas Conservation Commission. Gathering Pipeline Active Rig Permitted Acreage Weld Morgan Gathering Pipeline Active Rig Williams Divide Mountrail Burke McKenzie Permitted acreage and active rigs concentrated along Summit’s infrastructure, as legacy “core” areas of the DJ and Williston Basins are largely developed with limited remaining inventory Legacy Core Area Legacy Core Area

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Summit Capitalizes on Williston Development Migration to Williams & Divide Counties 10 Summit’s Williston Basin infrastructure spans Williams and Divide Counties, areas that are seeing a significant increase in development activity as producers migrate away from highly developed areas of McKenzie County 166 280 Crude Oil Production (MBbl/d) 436 356 Crude Oil Production (MBbl/d) 3,760 4,442 Number of Active Wells 2021(1) Current(2) 5,109 5,687 Number of Active Wells 2021(1) Current(2) ➢ Summit has secured 240,000 acres of new 10-year crude gathering dedications from two customers since 4Q-25 ➢ Three- and four-mile development and modern completions have materially improved individual well economics in Williams and Divide Counties ➢ Williams & Divide volumes have increased by 68% since 2021, offsetting an 18% decline in McKenzie volumes ▪ ~40% of active rigs are in Williams and Divide, compared to ~31% in McKenzie and ~29% in other counties ➢ Summit’s Rockies Segment expected to benefit as activity levels continue Source: Enverus (1) 2021 production statistics represent 12-month average; Active wells as of December 2021 (2) Current production and active wells as of December 2025 Williams & Divide County McKenzie County +113 MBbl/d 2021(1) to Current(2) - 81 MBbl/d 2021(1) to Current(2) 2021(1) Current(2) 2021(1) Current(2) New Area of Dedication Rigs by Area MT Williston Area Map Williams & Divide 40% McKenzie 31% Other 29%

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Active Permitting in DJ Basin Positioning for Long-Term Growth 11 Summit’s expansive gathering footprint and natural gas processing capacity in the DJ Basin is well positioned to support long-term volumetric growth as existing customers secure over 240 new well permits Sources: Enverus, Colorado Oil and Gas Conservation Commission. DJ Overview DJ Basin Development Map Customers Actively Permitting ➢ Summit’s infrastructure located behind sizeable permitting activity ➢ Summit’s capacity un-matched in this area of the basin ➢ Diversified set of producers, both private and public, actively permitting ➢ Activity would result in significant volume growth in the area, while legacy areas of the DJ Basin decline >39,000 Acres Permitted >240 Wells Permitted 5 Active Customers 162 MMcf/d Volume 235 MMcf/d Capacity ~69% Capacity Utilization Weld Morgan Logan Laramie Kimball CO WY NE Gathering Processing Plant New Development: Bison Chevron SM Energy Fundare Peoria Other

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$54 $88 $17 $76 $3 $239 $62 Adjusted EBITDA Interest Maintenance Capex Growth Capex Other Free Cash Flow Strong Free Cash Flow Generation with an Attractive Yield 12 Summit benefits from significant operating leverage which results in strong free cash flow (“FCF”) generation and an attractive FCF yield ➢ Summit has made significant investment over the past decade building out a sizeable gathering and processing footprint ➢ Capital expenditures generally limited to low-cost pad connections to support continued customer development ▪ Over the past 12-months, Summit has incurred ~$8 million of non-recurring capital expenditures to support its acquisition of Tall Oak and optimize its Williston basin footprint ➢ While Summit continues to focus on debt-repayment to achieve its 3.5x leverage target, investors benefit from ~8% free cash flow yield and ~9% free cash flow yield when normalizing for non-recurring capital expenditures Note: Please refer to the appendix for a reconciliation of Free Cash Flow to a GAAP measure (1) Last-twelve month period from Q3 2025 through Q2 2026 (2) Represents non-recurring capital expenditures over the last-twelve months to support the acquisition of Tall Oak and optimize Williston basin footprint (3) Includes cash interest paid and senior notes adjustment (4) Includes growth capital expenditures and investments in equity method investees (5) Includes cash paid for taxes and distributions on Subsidiary Series A Preferred Units Free Cash Flow Generation Last-Twelve-Month Free Cash Flow Reconciliation(1) ($ in millions, except per share metrics) Includes ~$7 MM for Tall Oak integration and compressor relocations and ~$1 MM for the Williston optimization project (3) (4) (5) (2) Reported Adj. As-Adj. FCF ($ in millions) $54 $8 $62 (/) Shares Outstanding 20 0 20 FCF / Share $2.68 $3.07 (/) SMC Share Price $33.54 $33.54 FCF Yield 8% 9%

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Historical Average (2023–2025) 2026E 2030E Double E Contributions Base Business Capex Summit’s Highly Visible Growth Outlook (1) (1) Illustrative Growth Outlook assumes Double E’s Current Contracted case (~$80 million of annual Adjusted EBITDA) and assumes that annual well connect cadence in the Rockies & Mid-Con segments from 2027 to 2030 are in-line with past 3-yr historical averages. Piceance segment reflects roll-off of $18 million of MVC related shortfall payments from 2025 to 2H 2026 and no well connects from 2027-2030 (2) “Existing Contracts” represent the MVC quantities that Double E shippers have contracted to with firm transportation service agreements and related negotiated rate agreements. (3) “Announced Contracts” represent the MVC quantities of new precedent agreements for projects not yet placed into service. 13 G&P Segment - Well Connect Activity Permian - Double E Growth Outlook Moderating Capex ($MM) Segment Adjusted EBITDA Contribution High returning capital investments in Permian & Rockies Segments in 2026–2028 transitions back to primarily maintenance and well connect capex in out years Contracted Adj. EBITDA expected to reach ~$80MM by 2030, with potential to grow to $100MM+ by 2030 Well connects expected to return to historical levels in 2027+ as key Rockies customers resume development activity Segment Adjusted EBITDA contribution shifts toward Permian and Rockies segments over time Segment Adjusted EBITDA ($MM) Existing Contracts(2) Announced Contracts(3) Expansion Upside Rockies Segment Mid-Con Segment Piceance Segment 0–56 101–159 ~95 ~135 20–38 ~26 ~35 173 ~121 ~170 Histroical Average (2023–2025) (Ranges shown within segments) 2026E (Midpoint) Forecasted Average (2027–2030) 2026E 2030E +$100 MM (1)(1) Revised Guidance: $100–$120 Long-Term: ~$50–$70~$60–$70 Historical Average (2023 – 2025) 2026E 2030E Double E Contributions Base Business Capex Historical Average (2023 – 2025) 2026E (Midpoint) Forecasted Average (2027 – 2030) 101 – 159 20 – 38 ~95 ~26 ~135 ~35 173 ~121 ~170 0 – 56 Summit’s existing portfolio is well positioned to add over $100MM(1) of organic EBITDA growth by 2030 Rockies ~45% Mid-Con ~30% Piceance ~3% Permian ~22% Rockies 39% Mid-Con 35% Piceance 12% Permian 13% 1,069 2,205 2,500+ ~$34 ~$80 ~$100+ 2025A Contracted Capacity Fully Contracted Expansion Segment Adjusted EBITDA ($MM) Contracted Volume (MMBtu/d)

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Opportunistic M&A Building Scale 14 End of 2019 End of 2022 Current Kimball CheyenneLaramie Weld Logan Wyoming Colorado Nebraska 805 Miles of Pipeline125 Miles of Pipeline 885 Miles of Pipeline 185 MMcf/d Processing Capacity60 MMcf/d Processing Capacity 235 MMcf/d Processing Capacity Kimball CheyenneLaramie Weld Logan Washington Wyoming Colorado Nebraska Morgan Gathering Pipeline Processing Plant Gathering Pipeline Processing Plant Kimball CheyenneLaramie Weld Logan Wyoming Colorado Nebraska Gathering Pipeline Processing Plant Total capital deployed $395M Across 3 transactions Entry multiple 5 – 6x Adjusted EBITDA multiple Volume Throughput Increase >450% Natural gas volume throughput from Q4 2019 to Q4 2025 Washington Morgan Washington Morgan DJ Basin Bolt-on Acquisition Case Study

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13.9x 11.6x 11.5x 10.2x 8.7x 8.1x 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x Peer A Peer B Peer C Peer D Peer E SMC Attractive Relative Trading Multiple & Growing Earnings Profile 15 Summit represents an attractive relative value compared to “Independent” G&P Universe (1) As of 06/30/2026. Shares outstanding includes Class A and Class B common stock. (2) Market data as of 08/26/2026. Wall Street consensus estimates; Peer group includes TRGP, KNTK, AM, KGS, and USAC. (3) Includes new precedent agreements for projects not yet placed into service. (4) In Existing Contracts case, expansion capital represents an incremental $215 million of 8/8ths plant connection capital, interconnect capital, and the midpoint compressor station project. Fully Contracted case represents the Existing Contracts capit al plus additional plant connections and interconnect capital. Figures in the table represent Summit’s 70% interest. All incremental expansion capex is expected to be funded with asset -level financing. (5) Represents 8/8ths valuation. Summit Enterprise Value(1) Significant potential value uplift to Summit stakeholders commercializing Double E 11.2x Peer Average 10.0x 10.4x 10.5x 10.5x 11.0x 11.0x Ann. Date Jun-21 May-24 Feb-22 Nov-24 Oct-19 Nov-20 EV ($MM)(5) $1,225 $3,375 $3,428 $1,200 $2,250 $3,320 Target Asset Stagecoach Gulf Coast Express Pipeline Gulf Coast Express Pipeline Guardian Pipeline, Midwestern Gas Transmission and Viking Gas Transmission Haynesville Gathering System (Momentum Midstream) NGPL System Double E Illustrative Residual Equity Value Long Haul Pipeline Transactions Comps EV / 2026E EBITDA(2)Summit Enterprise Value(1) EV / 2026E EBITDA(2) ($ in millions unless otherwise noted) 30-Jun-26 Share Price in dollars (as of 26-Aug-26) $34.02 Shares Oustanding (in millions) 20.3 Market Capitalization $691 Cash $21 ABL Revolving Credit Facility (Due July 2029) $79 8.625% Senior Secured Second Lien Notes (Due Oct 2029) 825 Permian Transmission Term Loan Facility, net of cash (Due Mar 2031) 340 Total Debt $1,244 Total Debt, net of Cash $1,223 Series A Preferred Stock $64 Total Enterprise Value $1,978 TEV / 2026E Adjusted EBITDA 8.1x ($ in millions) With Existing Fully Contracted Contracts(3) Expansion Double E EBITDA (net to SMC) ~$80 ~$100 (x) Estimated EBITDA Multiple 10.5x 10.5x Estimated Double E Enterprise Value (net to SMC) $840 $1,050 (-) Permian Transmission Term Loan, net of cash $340 $340 (-) Expansion Capital(4) 150 180 Illustrative Double E Residual Equity Value, net to SMC $350 $530

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Key Investment Takeaways 16 Summit Midstream Corporation (NYSE: SMC) is a fee-based, multi-basin platform with visible growth, strong cash conversion and trades at a 30% discount to its peers • ~30% discount to G&P peer average: Summit’s free cash flow profile, contract duration, and growth expectations are comparable to peers trading at 11.2x • Expect an increasing contribution from Double E Pipeline, a long-haul pipeline asset with several precedent transaction multiples ranging from 10.0x – 11.0x EBITDA 5 Attractive Valuation 8.1x TEV/2026E EBITDA vs. 11.2x peer avg • Double E: ~$34MM → ~$80MM Adjusted EBITDA by 2030 backed by 1.1 Bcf/d of newly signed 10-year take-or-pay contracts • Fully Contracting mainline compression expansion could lead to more than $100 million of Permian Segment Adjusted EBITDA • Development activity accelerating: 240+ permitted DJ Basin wells, new 200,000-acre and 40,000-acre Williston dedications with additional commercial opportunities across the portfolio 4 Visible Organic Growth >8% Expect ~$100MM of Organic EBITDA growth by 2030 • ~85% fixed-fee gross margin insulates Summit from the commodity price volatility • >7.0 year weighted average contract life with 5.9 million dedicated acres under long-term contract across all six basins • Diversified customer base ranging from large-scale publics to single-basin focused privates 2 Quality Earnings ~85% Fixed fee-based gross margin • Low-capex model: system backbone built-out and well connections require minimal incremental investment; long-term capex guidance of ~$50– 70M drives FCF generation • Near-term capital allocation focused on highly economic growth projects and de-levering: expect free cash flow to reduce leverage to our long-term leverage target of 3.5x • Expect to resume common dividend policy once leverage target achieved 3 High FCF Conversion 8–9% FCF yield (reported / normalized) • Permian, Williston, DJ, Barnett, Arkoma, Piceance: six resource plays with independent growth drivers and no single point of concentration • Exposed to both natural gas and crude oil-oriented basins • Leveraging Scalable Footprint: Critical infrastructure is already built out with capacity to service additional volume growth 1 Diversified 6 Plays No single basin >35% of EBITDA

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Diversified Asset Portfolio

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Diversified G&P Operating Footprint 18 Summit's diversified operations, services and customers provide cash flow stability. Summit intends to continue to allocate growth capital in a prudent fashion and subject to high return thresholds (1) Unless otherwise noted, includes Summit’s pro-rata share of Double E segment adjusted EBITDA, capital contributions, volume throughput and weighted average contract life. Weighted average contract life and MVCs does not include the recently announced new long-term firm contracts. Permian(1) Rockies Mid-Con Piceance Williston DJ Services Provided Natural Gas Transmission Crude Oil & Produced Water Gathering Natural Gas Gathering & Processing & Crude Oil Gathering Natural Gas Gathering & Processing Natural Gas Gathering & Processing 2Q’26 EBITDA $9.4 MM $30.4 MM $21.4 MM $8.7 MM 2Q’26 Capex n/a $17.0 MM $6.8 MM $0.5 MM 2Q’26 Volume Throughput DBLE (8/8th): 859 MMcf/d Liquids: 68 Mbbl/d Gas: 162 MMcf/d 523 MMcf/d 214 MMcf/d AMI (Acres) n/a 2,600,000 2,870,000 434,000 MVCs DBLE (8/8th): 2.6 Tcf 39 Bcfe n/a 48 Bcf Wtd. Avg. Contract Life DBLE: 6.4 years Liquids: 7.3 years Gas: 5.9 years 7.1 years 7.5 years Key Customers Large U.S. Independent Producer Large U.S. Independent Producer Crude Oriented Gas Oriented

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Active Development Across Summit's Footprint 19 Customer rig activity and DUC inventory provides line of sight toward 2026 estimated well connections that we expect to drive significant free cash flow (1) Based on Q2 2026 volumes and system capacities. (2) Represents 1.115 Bcf/d of contracts relative to estimated capacity of 1.6 Bcf/d. Segment Capacity & Utilization(1) Customer Active Rigs DUCs Well Connections Volume Throughput Segment Adjusted EBITDA Capex Low High Low High Low High Low High Rockies 370 MBbl/d ~18% 235 MMcf/d ~69% ~75 90–100 Liquids: 65–90 MBbl/d Gas: 160–170 MMcf/d $95–$125 million Moderate Pad Connections Mid-Con 890 MMcf/d ~59% 0 26 485–520 MMcf/d $95–$105 million Moderate Pad Connections & Integration Capital Piceance 1.3 Bcf/d ~17% 0 0 230 MMcf/d ~$35 million Limited Pad Connections Permian 1.60 Bcf/d ~70%(2) NM Rig Count x 91 ~900 MMcf/d ~$37 million Moderate Additional plant connections Asset – Level ~6.1 Bcfe/d x 7 ~75 116 – 126 $262–$302 million $85–$105 million Unallocated G&A n.a. ~$(37) million Total (Original) $225–$265 million $85–$105 million Revised Guidance $235–$255 million $100–$120 million 2026E Guidance

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Ample System Capacity Limits Capex Requirements 20 ➢ In several areas, Summit benefits from (i) customer reimbursements for capex, (ii) systems being fully built-out and customer “infill” drilling, and (iii) customers delivering volumes directly to our systems ➢ Rockies Segment: ▪ DJ Basin system provides ample processing capacity for incremental volume growth ▪ Certain key customers reimburse Summit for all, or a portion, of connection costs ▪ Expansive gathering footprint limits incremental pad connection capex ➢ Mid-Con Segment: ▪ Significant unutilized capacity in the Mid-Con to service incremental volumes ▪ Expansive gathering footprint limits incremental pad connection capex ➢ Piceance Segment: ▪ Expansive gathering footprint limits incremental pad connection capex ▪ In 2025, re-deployed 50 MMcf/d of compression capacity to replace leased compressors in the Arkoma ➢ Permian Segment: ▪ Potential for additional processing plant connections ▪ Any new growth project would likely be funded with nonrecourse asset-level financing ▪ 1.6 Bcf/d of existing capacity, reached FID on expansion to 2.4 Bcf/d with mid-point compressor project (1) Includes oil and produced water at a 6:1 conversion ratio. (2) Represents 1.115 Bcf/d of contracts relative to estimated capacity of 1.6 Bcf/d. Area Strategy & Key Themes Limited to no incremental cost Incremental costs proportionate with activity Significant Operating Leverage Incremental Pad Statistics (MMcf/d, except Williston-Liquids) System Connection Costs 2Q'26 Volume Capacity Utilization Liquids 68 370 18% DJ 162 235 69% Rockies Segment (1) 570 2,455 23% Permian Segment (2) NA 1,115 1,600 70% Piceance Segment 214 1,259 17% Mid-Con Segment 523 890 59%

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Permian Segment 21 Double E represents a significant value catalyst, connecting New Mexico natural gas to Waha Hub ➢ Double E provides a critical outlet for growing natural gas production in the infrastructure- constrained northern Delaware ▪ 70% / 30% joint venture between Summit and Exxon, the largest contiguous acreage holder in the region ➢ The Double E route extends ~135 miles through the core of the Delaware Basin ▪ Near ~40 natural gas processing plants with ~9 Bcf/d of capacity ➢ Double E offers significant residual equity value potential net to Summit ▪ Precedent transactions valued at 10.0x – 12.0x EBITDA ▪ Highly accretive EBITDA growth through commercialization of existing capacity and execution of sub-4.0x expansion project if fully commercialized ➢ Reached FID on the mainline compression expansion, anchored by 550 MMcf/d of take-or-pay agreements—total contracted firm capacity now ~2.2 Bcf/d Source: Enverus, Baker Hughes Rig Report New Mexico Horizontal Rig Count Double E MapArea Strategy & Key Themes 54 64 72 79 87 95 99 109 106 105 106 108 103 102 108 107 101 104 93 87 95 96 92 0 2 4 6 8 10 12 0 20 40 60 80 100 120 Q4 20 Q1 21 Q2 21 Q3 21 Q4 21 Q1 22 Q2 22 Q3 22 Q4 22 Q1 23 Q2 23 Q3 23 Q4 23 Q1 24 Q2 24 Q3 24 Q4 24 Q1 25 Q2 25 Q3 25 Q4 25 Q1 26 Q2 26 Lea and Eddy County Natural Gas Production (Bcf/d) New Mexico Rig Count Rig Count Eddy and Lea County Gas Production

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75 70 76 74 78 72 66 64 68 2 0 17 8 6 5 0 13 0 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Rockies Liquids (Mbbl/d) Well Connects Rockies Segment: Williston Basin Source: DrillingInfo as of August 2026. (1) Summit acquired Moonrise Midstream on March 10, 2025. Q1 2025 includes partial month flow for the acquired assets. 22 Geographically expansive platform providing multiple service offerings to top producers in the play Williston Basin MapArea Strategy & Key Themes Operator: Chord # of Wells: 5 1st Prod: Jul-23 Crude Avg. IP: 658 Bbl/d Water Avg. IP: 1,260 Bbl/d A Operator: Kraken # of Wells: 5 1st Prod: Aug-23 Crude Avg. IP: 937 Bbl/d B Operator: Kraken # of Wells: 5 1st Prod: Dec-24 Crude Avg. IP: 913 Bbl/d E A Operator: Kraken # of Wells: 11 1st Prod: Jan-24 Crude Avg. IP: 785 Bbl/d D C B D E Divide Burke Sheridan Roosevelt Williams Mountrail McKenzie NORTH DAKOTA MONTANA Operator: Kraken # of Wells: 6 1st Prod: Jun-23 Crude Avg. IP: 991 Bbl/d C Rockies Quarterly Volumes & Well Connects ➢ Expansive footprint with 550+ miles of crude oil and produced water pipelines with AMIs totaling ~0.7 million acres ▪ Multiple delivery points maximize downstream optionality ➢ Robust and diversified customer base with multiple service offerings ▪ Substantial PDP base ➢ Consolidation has enabled customers to continue to extend lateral lengths from 2-miles to 3-miles and 4-miles ➢ Executed a 10-year extension of certain gathering agreements with key customer in the Williston Basin in Q2 2025 ➢ Signed two new 10-year, crude gathering agreements spanning a total of 240,000-acre area of dedications with new customers ▪ Both customers currently running a rig on dedicated acreage (1)

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Rockies Segment: DJ Basin Source: DrillingInfo as of August 2026. (1) Excludes overlapping acreage. (2) Normalized to 10,000' lateral length. (3) Summit acquired Moonrise Midstream on March 10, 2025. Q1 2025 includes partial month flow for the acquired assets. 23 Sizable and integrated footprint with top-tier customers in rural DJ Basin ➢ Integrated G&P platform provides a scalable, reliable and sustainable solution to producers in the area ▪ Provide natural gas gathering & processing, as well as crude oil gathering and freshwater delivery ➢ High-pressure lines interconnect Makena Plant, Hereford Plant, Centennial Plant and Redtail Plant enabling significant connectivity ➢ Over 1.9 million(1) acre AMI dedicated under long-term contracts with a weighted average life of ~5.9 years ➢ Well-positioned to compete for large-scale development of the NE Wattenberg from new commercial agreements ➢ Opportunities for additional bolt-on acquisitions in the area Rockies Quarterly Volumes & Well Connects DJ Basin MapArea Strategy & Key Themes (3) A B Operator: Large Independent # of Wells: 6 1st Prod: Jan-24 Crude Avg. IP: 679 Bbl/d Gas Avg. IP: 0.7 MMcf/d B Operator: Peoria Resources # of Wells: 5 1st Prod: Jan-24 Crude Avg. IP: 560 Bbl/d Gas Avg. IP: 1.1 MMcf/d A Operator: Bison IV # of Wells: 8 1st Prod: Apr-24 Crude Avg. IP: 730 Bbl/d Gas Avg. IP: 1.2 MMcf/d C CCentennial Gas Plant Makena Gas Plant Yenter Gas Plant Hereford Gas Plant Jackson Lake Gas Plant Redtail Gas Plant Morgan Kimball CheyenneLaramie Weld Logan Gas Gathering Crude Gathering Fresh Water Gathering Processing Plant Washington Operator: Bison IV # of Wells: 5 1st Prod: Jan-25 Crude Avg. IP: 466 Bbl/d Gas Avg. IP: 0.4 MMcf/d D D E Operator: Fundare Resources # of Wells: 7 1st Prod: Aug-23 Crude Avg. IP: 540 Bbl/d(2) Gas Avg. IP: 0.9 MMcf/d(2) E 130 128 131 129 147 158 160 167 162 18 29 6 22 32 4 33 18 16 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Rockies Gas (MMcf/d) Well Connects

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Mid-Con Segment: Barnett Shale System fully developed with minimal capex requirements A B 24 Operator: TOTAL # of Wells: 5 1st Prod: Sep-23 Gas Avg. IP: 5 MMcf/d A Operator: TOTAL # of Wells: 11 1st Prod: May-24 Gas Avg. IP: 7 MMcf/d B ➢ Continuous improvement in the reservoir, with EURs increasing from 2.8 Bcf in 2019 to over 4.5 Bcf today ➢ Most recent customer well results have exceeded expectations ▪ Recently completed wells generated 6–8 MMcf/d IPs ➢ Anchor customer: TotalEnergies’ Barnett acreage is its only operated source of U.S. production to meet its LNG commitments ▪ TotalEnergies also owns gas-fired generation in the Dallas and Houston areas ➢ Long-term, fixed fee contracts, with weighted avg. remaining life of 4.0 years and difficult to replicate system in Dallas Fort-Worth area (1) Source: DrillingInfo as of August 2026. (1) Summit acquired Tall Oak Midstream III on December 2, 2024. Q1 2025 was the first complete quarter of flow pro forma contribution. Mid-Con Quarterly Volumes & Well Connects Barnett Shale MapArea Strategy & Key Themes 202 255 329 488 502 508 489 476 523 232 275 348 14 9 0 11 9 12 6 6 20 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Reported Volumes (MMcf/d) Estimated Shut-ins (MMcf/d) Well Connects

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Mid-Con Segment: Arkoma Basin Expansive gathering, compression and processing system that can accommodate significant growth Source: DrillingInfo as of August 2026. Arkoma Basin Map ➢ Key customers have 10+ years of economic inventory across Tall Oak’s dedicated acreage ▪ Contracts are long-term, primarily fixed fee, with significant dedicated leased acreage ➢ Limited well connects required to maintain and grow volumes ➢ Opportunities for bolt-on acquisitions in the area ➢ Expect key customer to resume drilling in the second half of 2026 Area Strategy & Key Themes Operator: Calyx # of Wells: 3 1st Prod: July-22 Gas Avg. IP: 11.5 MMcf/d GPM: 5.0 A Operator: Canyon Creek # of Wells: 3 1st Prod: Mar-21 Gas Avg. IP: 8.4 MMcf/d GPM: 6.9 B A B Gas Gathering Processing Plant Panther Creek Plant Stanberry Plant 25

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Piceance Segment Gathering system scale provides significant operating leverage 26Source: DrillingInfo as of August 2026. Piceance Basin Map ➢ Key customers, QB Energy and Flywheel Energy, have consolidated several smaller producers in the basin driving cost and efficiency gains ▪ Quantum backed QB Energy recently acquired Caerus and Wincoram backed Flywheel Energy acquired Terra ➢ MVCs working as designed, providing cash flow stability ➢ Long-term, primarily fixed fee contracts, with weighted avg. remaining life of 7.5 years ➢ High free cash flow generation; $8.7 million of adj. EBITDA in 2Q 2026 on $0.5 million of capital expenditures Area Strategy & Key Themes Legend Natural Gas Pipeline A B Rio Blanco Garfield Mesa Operator: Flywheel # of Wells: 9 1st Prod: Sep-19 Gas Avg. IP: 2 MMcf/d A Operator: Flywheel # of Wells: 56 1st Prod: Mar-23 Gas Avg. IP: 2 MMcf/d B Piceance Quarterly Volumes & Well Connects 289 284 277 266 263 259 245 227 214 0 0 0 0 0 0 0 0 0 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Reported Volumes (MMcf/d) Well Connects

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Appendix

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Substantial Progress Executing Corporate Strategy 28 Summit continues to be focused on executing its corporate strategy, with several successes to date $850M+ Fixed obligations retired ~$700M Northeast divestiture proceeds (~7.3x) ~$20M Annual run-rate expense savings >15x Non-core divestiture multiple 1.2 Bcf/d New firm contracts on Double E >$75M Double E Adj. EBITDA target, 2029 2019 – 2021 Strengthen the Foundation ▪ ~$20 million annual savings via re-org and office consolidation ▪ Acquired ECP interests; retired ~18% of outstanding units ▪ Retired $850+ million of fixed obligations ▪ Refinanced ~$1.0 billion of debt with covenant-lite structure 2022 – 2024 Optimize & Reposition ▪ Non-core assets divested at >15.0x combined EBITDA multiple ▪ DJ Basin acquired at ~4.0x EBITDA ▪ $825 million Second Lien Notes and $500 million upsized ABL extending maturities to 2029 ▪ Northeast divested for ~$700M (~7.3x multiple) ▪ Reorganized from an MLP to C-Corp ▪ Tall Oak III acquired in December 2024 2025 – 2026 Commercialize & Scale ▪ Acquired Moonrise Midstream in DJ Basin in March 2025 ▪ 1.1 Bcf/d of new firm contracts signed over the past twelve months, including 550 MMcf/d from the recent open season ▪ 10-year crude oil gathering agreements covering more than 240,000 acres in Williston ▪ Double E refinanced; $85M one-time distribution to Summit Maximize FCF (Disciplined Capital Allocation) Support Well Connections & Execute on Organic Growth (Supportive oil & gas fundamentals) Commercialize & Expand Double E Pipeline (10x-12x EBITDA Multiple Business) Execute on Strategic, Credit and Value Accretive Acquisitions & Divestitures With “Go-Forward” Priorities Continuing to Focus on Maximizing Shareholder Value

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Majority Independent Board of Directors Summit adopted an independent governance structure when the MLP acquired its General Partner in 2020 29 (1) As the holder of Class B Common Stock representing approximately 32% of the voting rights in Summit, Tailwater Capital will have the right to elect up to four directors. Summit has been notified by Tailwater that Tailwater intends to elect the individuals included on this slide, all of whom have consented to such election, to the S ummit board, pending compliance with all relevant Delaware and NYSE stock exchange requirements, as determined by the Summit board, which determination has not yet been made. Board Requirements Board of Directors Overview ➢ All directors are subject to public election, including beginning in 2023 our President and CEO ➢ All directors other than Chair/CEO are independent, all committee members are independent, and the Board has designated a lead independent director Board Member Summary Background Heath Deneke (Class II) ▪ President, CEO and Chairman ▪ Board Member Since: 2019 ▪ Prior Experience / Affiliations: Crestwood Equity Partners, El Paso Corporation James Cleary (Class III) ▪ Lead Independent Director ▪ Board Member Since: 2020 ▪ Prior Experience / Affiliations: Global Infrastructure Partners, El Paso Corporation, Sonat Inc. Carolyn Stone (Class II) ▪ Independent Director ▪ Board Member Since: 2026 ▪ Prior Experience / Affiliations: Civeo Corporation, Synagro Technologies Inc., Dynegy Inc., PricewaterhouseCoopers LLP Lee Jacobe (Class I) ▪ Independent Director ▪ Board Member Since: 2019 ▪ Prior Experience / Affiliations: Kelso & Company, Barclays, Lehman Brothers, Wasserstein Perella & Co. Jerry Peters (Class I) ▪ Independent Director & Financial Expert ▪ Board Member Since: 2012 ▪ Prior Experience / Affiliations: Green Plains Inc., ONEOK Partners, L.P., KPMG LLP Robert McNally (Class II) ▪ Independent Director ▪ Board Member Since: 2020 ▪ Prior Experience / Affiliations: EQT Corporation, Precision Drilling Corporation, Kenda Capital LLC, Dalbo Holdings, Warrior Energy Services Corp., Simmons & Company, Schlumberger Limited Rommel Oates (Class III) ▪ Independent Director ▪ Board Member Since: 2022 ▪ Prior Experience / Affiliations: Oates Energy Solutions, International Association of Hydrogen Energy, True North Venture Partners, Aquahydrex Pty Ltd., Praxair Inc. Jason Downie(1) (Class I) ▪ Co-Founder and Managing Partner, Tailwater Capital ▪ Prior Experience / Affiliations: Goodnight Midstream, Silver Creek Midstream, Renovo Resources, Tall Oak Midstream, Tailwater E&P (Royalties & Non-Op), HM Capital and Donaldson, Lufkin & Jenrette Edward Herring(1) (Class II) ▪ Co-Founder and Managing Partner, Tailwater Capital ▪ Prior Experience / Affiliations: Producers Midstream, Goodnight Midstream, Silver Creek Midstream, Cureton Midstream II, Blue Tide Environmental, Frontier Carbon Solutions, Tailwater E&P (Royalties & Non -Op), Ash Creek Renewables, Freestone, Continuus Materials, HM Capital and Goldman Sachs Stephen Lipscomb(1) (Class III) ▪ Partner, Tailwater Capital ▪ Prior Experience / Affiliations: Copperbeck Energy Partners, Cureton Midstream, Frontier Carbon Solutions, Producers Midstream, Silver Creek Midstream, Tall Oak Midstream, TexStar Midstream Logistics, Crestwood Equity Partners, Brazos Private Equity Partners and JPMorgan Drew Winston(1) (Class III) ▪ Principal, Tailwater Capital ▪ Prior Experience / Affiliations: Cureton Midstream, Tall Oak Midstream, Goodnight Midstream, Producers Midstream, Ash Creek Renewables, Triten Energy Partners, Renovo Resources, Sage Midstream, Austin Ventures and Simmons & Company International Nomination Process ➢ The following constituents may nominate eligible persons for election: ▪ The Board ▪ A stockholder of record who complies with the corporate bylaws Election Process ➢ The Board may nominate and elect a person to fill any vacancy, including newly created directorship ➢ Summit hosts an annual meeting of stockholders to elect directors on a staggered basis for a 3-year term ▪ Class I – in 2028 (3 directors) ▪ Class II – in 2026 (4 directors) ▪ Class III – in 2027 (4 directors)

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$825 $79 $340 2026 2027 2028 2029 2030 2031 ($ in millions) 6/30/2026 As Reported Unrestricted Cash $21 ABL Revolving Credit Faciliity (Due July 2029) 79 8.625% Senior Secured Second Lien Notes (Due Oct 2029) 825 Total Debt $904 Total Debt, net of Cash $883 Series A Preferred Stock 64 Recourse Obligations, net of Cash $947 Selected Credit Metrics(1): 1st Lien Leverage Ratio 0.3x Total Leverage Ratio 4.1x Double E Related: Permian Transmission Term Loan Facility, net of cash (Due Mar 2031) $340 Balance Sheet Details 30 Note: Summit quarterly recourse debt balances include capital leases, which are not shown on the Summit capitalization table. As of 06/30/2026. (1) Credit metrics calculated per Summit’s ABL Revolving Credit Facility as pertinent. (2) Reflects drawn amounts under the $500mm ABL Facility. Overview Pro Forma Capitalization ➢ Refinanced debt in July 2024, creating multi-year runway to facilitate further harvesting of free cash flow and de-levering • $500 million ABL Revolver provides ample liquidity and financial flexibility ▪ Borrowing base determined by value of above ground, mission critical assets and accounts receivable ▪ Priced at SOFR + 250–325 bps ▪ Minimal restrictive covenants: (i) maximum 2.5x first lien leverage ratio and (ii) minimum interest coverage of 2.0x • 8.625% senior secured 2L notes with covenant light restrictions • Ability to pay preferred distributions if net leverage is below 4.5x • Ability to pay common distributions if net leverage is below 4.0x Debt Maturity Schedule ABL(2)Secured Notes Summit Permian Transmission Term Loan (non-recourse to Summit)

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Driving Efficiencies Through AI 31 Areas under evaluation for AI implementation across Summit's operating footprint to address over $100 million of addressable spend OPERATIONS Predictive Equipment Maintenance Monitoring of compressors and field equipment to predict failures before they occur, reducing unplanned downtime and repair costs COMMERCIAL Scheduling Optimization Optimize throughput scheduling across gathering systems FINANCE & REPORTING Automated Financial Reporting AI-assisted generation of financial disclosures, earnings materials, and regulatory filings to reduce manual administrative hours LAND & CONTRACTS Contract Review & Land Management Accelerate review of gathering agreements, easements, and right-of-way documents across the expanded multi-basin portfolio ENERGY MANAGEMENT Compression Optimization AI-powered routing and load balancing for the compressor fleet CORPORATE Workflow Automation & Productivity AI assistants embedded in HR, procurement, and IT workflows to improve output per employee and manage headcount growth

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10 15 20 42 20 35 50 ~3% ~0% ~5% ~10% Historical Average 0% Growth 5% Growth 10% Growth 68 82 82 74 2022 PF 2023 PF 2024 PF 2025 PF Rockies Segment: Liquids Connections & Volume Sensitivity Source: As-reported information from 10Q and 10K filings; Summit management estimates. (1) Summit acquired Sterling and Outrigger DJ on December 1, 2022; Summit acquired Moonrise Midstream on March 10, 2025. (2) Represents a 2022 – 2025PF CAGR; Represents simple average of annual PF well connections (3) For illustrative purposes and based on Summit estimates. Represents an estimated 5-year throughput volume CAGR under a range of assumed well connections per year. Assumes 15,000’ lateral lengths. 32 Overview Historical Pro Forma Well Connections ➢ For comparative purposes well connections and volume throughput have been adjusted for the pro forma impact of the Sterling and Outrigger DJ acquisitions in December 2022 and Moonrise acquisition in March 2025 ➢ Historical well connections from 2022 through 2025 have averaged 42 wells per year, with a high of 65 and a low of 19 ➢ Throughput volume has increased from 68 MBbl/d in 2022 to ~74 MBbl/d in 2025, representing a 3-year CAGR of ~3% ➢ The illustrative volume sensitivity is intended to provide a directional estimate of the number of well connections to maintain volumes, increase volumes by ~5% and increase volumes by 10% relative to 2025 ▪ The analysis also includes a sensitivity based on the estimated number of wells assuming Summit provides crude oil gathering, or crude oil and produced water gathering services Historical Pro Forma Throughput Volume Illustrative Volume Sensitivity(3) As-Reported Pro Forma Adjustment for Acquisitions(1) Annual Crude Only Wells to Achieve Growth Annual Crude & Water Wells to Achieve Growth Long-Term Annual Volume Growth Estimate Well Connections Volume Growth Average: 42 Wells As-Reported Pro Forma Adjustment for Acquisitions(1) 37 65 48 19 2022 PF 2023 PF 2024 PF 2025 PF Estimated Volume Growth SensitivityHistorical Average(2)

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95 55 85 120 ~7% ~0% ~5% ~10% Historical Average 0% Growth 5% Growth 10% Growth 125 135 153 152 2022 PF 2023 PF 2024 PF 2025 PF Rockies Segment: Natural Gas Connections & Volume Sensitivity Source: As-reported information from 10Q and 10K filings; Summit management estimates. (1) Summit acquired Sterling and Outrigger DJ on December 1, 2022; Summit acquired Moonrise Midstream on March 10, 2025. (2) Represents a 2022 – 2025PF CAGR; Represents simple average of annual PF well connections (3) For illustrative purposes and based on Summit estimates. Represents an estimated 5-year throughput volume CAGR under a range of assumed well connections per year. Assumes 10,000’ lateral lengths. 33 Overview ➢ For comparative purposes well connections and volume throughput have been adjusted for the pro forma impact of the Sterling and Outrigger DJ acquisitions in December 2022 and Moonrise acquisition in March 2025 ➢ Historical well connections from 2022 through 2025 have averaged 95 wells per year, with a high of 106 and a low of 78 ➢ Throughput volume has increased from 125 MMcf/d in 2022 to ~152 MMcf/d in 2025, representing a 3-year CAGR of ~7% ➢ The illustrative volume sensitivity is intended to provide a directional estimate of the number of well connections to maintain volumes, increase volumes by ~5% and increase volumes by 10% relative to 2025 Long-Term Annual Volume Growth Estimate Annual Wells to Achieve Growth Average: 95 Wells Historical Pro Forma Well Connections As-Reported Pro Forma Adjustment for Acquisitions(1) Historical Pro Forma Throughput Volume Illustrative Volume Sensitivity(3) As-Reported Pro Forma Adjustment for Acquisitions(1) 78 106 103 91 2022 PF 2023 PF 2024 PF 2025 PF Estimated Volume Growth SensitivityHistorical Average(2) Well Connections Volume Growth

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431 460 475 497 2022 PF 2023 PF 2024 PF 2025 PF Mid-Con Segment: Natural Gas Connections & Volume Sensitivity Source: As-reported information from 10Q and 10K filings; Summit management estimates. (1) Summit acquired Tall Oak on December 2, 2024 (2) Represents estimated impact of wells that were shut-in during 2023 and 2024 as a result of natural gas prices behind Summit’s Barnett system (3) Represents a 2022 – 2025PF CAGR; Represents simple average of annual PF well connections (4) For illustrative purposes and based on Summit estimates. Represents an estimated 5-year throughput volume CAGR under a range of assumed well connections per year. Assumes 10,000’ lateral lengths in the Arkoma and 6,000’ in the Barnett 34 Overview Historical Pro Forma Well Connections ➢ For comparative purposes well connections and volume throughput have been adjusted for the pro forma impact of the Tall Oak acquisition in December 2024 ➢ Historical well connections from 2022 through 2025 have averaged 33 wells per year, with a high of 47 and a low of 20 ➢ Throughput volume has increased from 431 MMcf/d in 2022 to ~497 MMcf/d in 2025, representing a 3-year CAGR of ~5% ➢ The illustrative volume sensitivity is intended to provide a directional estimate of the number of well connections to maintain volumes, increase volumes by ~5% and increase volumes by 10% relative to 2025 ▪ Analysis assumes average lateral length of 6,000’ in the Barnett and 10,000’ in the Arkoma ▪ Analysis assumes 50% Barnett and 50% Arkoma well connections Historical Pro Forma Throughput Volume Illustrative Volume Sensitivity(4) As-Reported Pro Forma Adjustment for Acquisitions(1) Shut-In Volumes(2) Average: 33 Wells As-Reported Pro Forma Adjustment for Acquisitions(1) 47 20 27 38 2022 PF 2023 PF 2024 PF 2025 PF 33 25 40 55 ~5% ~0% ~5% ~10% Historical Average 0% Growth 5% Growth 10% Growth Long-Term Annual Volume Growth Estimate Annual Wells to Achieve Growth Estimated Volume Growth SensitivityHistorical Average(3) Well Connections Volume Growth

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0 56 0 0 2022 2023 2024 2025 306 304 290 258 2022 2023 2024 2025 Piceance Segment: Natural Gas Connections & Volume Sensitivity Source: As-reported information from 10Q and 10K filings; Summit management estimates. (1) Represents a 2022 – 2025 CAGR; Represents simple average of annual PF well connections (2) For illustrative purposes and based on Summit estimates. Represents an estimated 5-year throughput volume CAGR under a range of assumed well connections per year. 35 Overview Historical Pro Forma Well Connections ➢ Historical well connections from 2022 through 2025 have averaged 14 wells per year, with a high of 56 and a low of 0 ➢ Throughput volume has decreased from 306 MMcf/d in 2022 to ~258 MMcf/d in 2025, representing a 3-year CAGR of ~(6)% ➢ The illustrative volume sensitivity is intended to provide a directional estimate of the existing production decline rate assuming no new well activity, as well as the number of well connections to maintain volumes and increase volumes by ~8% relative to 2025 Illustrative Volume Sensitivity(2) As-Reported Average: 14 Wells As-Reported Historical Pro Forma Throughput Volume Long-Term Annual Volume Growth Estimate Annual Wells to Achieve Growth 14 50 100 ~(6%) ~(8%) ~0% ~8% Historical Average PDP Decline 0% Growth 8% Growth Estimated Volume Growth SensitivityHistorical Average(1)

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Reportable Segment Adjusted EBITDA 36 (1) Segment adjusted EBITDA is a non-GAAP financial measure. We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income (excluding interest income), (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to minimum volume commitments ("MVC") shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) share-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains. (2) Includes our proportional share of adjusted EBITDA for Double E. We define proportional adjusted EBITDA for our equity method investees as the product of total revenues less total expenses, excluding impairments and other noncash income or expense items; multiplied by our ownership interest during the respective period. (3) Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items and transaction costs. (4) Adjusted EBITDA is a non-GAAP financial measure. Three Months Ended June 30, Six Months Ended June 30, ($s in 000s) 2026 2025 2026 2025 Reportable segment adjusted EBITDA (1): Rockies 30,359 25,235 $ 56,734 $ 50,104 Permian (2) 9,364 8,300 18,094 16,570 Piceance 8,662 10,474 18,232 22,260 Mid-Con 21,361 24,900 40,688 47,357 Total $ 69,746 $ 68,909 $ 133,748 $ 136,291 Less: Corporate and other (3) 9,047 7,815 18,857 17,691 Adjusted EBITDA (4) $ 60,699 $ 61,094 $ 114,891 $ 118,600

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Reconciliation of Net Income or Loss to adj. EBITDA, DCF and FCF (1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues. (2) Reflects our proportionate share of Double E. (3) Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers. (4) Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the six months ended June 30, 2026, the amount includes $2.5 million of transaction and other costs. For the six months ended June 30, 2025, the amount includes $7.7 million of transaction and other costs and $5.4 million of integration cost s. (5) Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on t he 2029 Secured Notes is paid semi-annually in arrears on each February 15 and August 15. (6) Represents cash flow available for distribution to preferred and common shareholders. Common dividends cannot be paid unless all accrued preferred dividends are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF. 37 Six Months Ended June 30 Year ended December 31, 2026 2025 2025 2024 2023 2022 2021 Net income / (loss) $ 1,399 $ 406 $ (1,906) $ (113,175) $ (38,947) $ (123,461) $ (19,949) Add: Interest expense 52,416 46,401 94,737 115,446 140,784 102,459 66,156 Income tax expense (benefit) 66 (456) (501) 146,678 322 325 (327) Depreciation and amortization(1) 54,028 59,041 115,097 101,585 123,702 119,993 119,995 Proportional adjusted EBITDA for equity method investees(2) 16,336 14,848 30,536 42,038 61,070 45,419 29,022 Adjustments related to capital reimbursement activity(3) (5,655) (3,876) (9,023) (9,909) (9,874) (6,041) (6,571) Share-based and noncash compensation 5,334 4,737 7,798 8,561 6,566 3,778 4,744 (Gain) loss on fair value of Tall Oak earn out 503 (8,479) 192 — — — — (Gain) loss on early extinguishment of debt — — — 50,075 10,934 — 3,523 (Gain) loss on asset sales, net 3 — 486 1 (260) (507) (369) Long-lived asset impairment — 71 2,725 68,260 540 91,644 10,151 (Gain) loss on interest rate swaps (797) 1,466 1,037 (4,127) (1,830) (16,414) — (Gain) loss on sale of business — 43 582 (82,187) 47 1,741 — Gain on sale of equity method investment — — — (126,261) — — — Other, net(4) 2,327 14,040 21,639 31,835 7,619 11,495 39,928 Less: Income from equity method investees 11,069 9,642 20,784 24,197 33,829 18,141 7,880 Adjusted EBITDA $ 114,891 $ 118,600 $ 242,615 $ 204,623 $ 266,844 $ 212,290 $ 238,423 Less: Cash interest paid 43,334 39,508 83,357 101,779 127,022 89,472 57,655 Cash paid for taxes — 265 299 22 15 149 191 Senior notes interest adjustment(5) — 4,935 5,332 2,497 1,847 4,315 4,757 Maintenance capital expenditures 7,876 8,007 17,311 11,673 12,357 10,964 7,532 Cash flow available for distributions(6) $ 63,681 $ 65,885 $ 136,316 $ 88,652 $ 125,603 $ 107,390 $ 168,288 Less: Growth capital expenditures 36,394 38,989 71,731 41,938 56,548 19,508 17,498 Investment in equity method investee 6,508 3,063 3,816 3,880 3,500 8,444 148,699 Distributions on Subsidiary Series A Preferred Units — 3,257 6,513 6,513 6,513 4,885 — Free Cash Flow $ 20,779 $ 20,576 $ 54,256 $ 36,321 $ 59,042 $ 74,553 $ 2,091

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Reconciliation of Net Cash Provided by Operating Activities to Adj. EBITDA and DCF (1) Reflects our proportionate share of Double E. (2) Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers. (3) Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the six months ended June 30, 2026, the amount includes $2.5 million of transaction and other costs. For the six months ended June 30, 2025, the amount includes $7.7 million of transaction and other costs and $5.4 million of integration cost s. (4) Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on t he 2029 Secured Notes is paid semi-annually in arrears on each February 15 and August 15. (5) Represents cash flow available for distribution to preferred and common shareholders. Common dividends cannot be paid unless all accrued preferred dividends are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF. 38 Six Months Ended June 30, ($s in 000s) 2026 2025 Cash flow available for distributions: Net Cash provided by operating activities $ 50,802 $ 53,243 Add: Interest expense, excluding amortization of debt issuance costs 48,603 44,422 Income tax expense (benefit), excluding federal income taxes (6) 98 Changes in operating assets and liabilities 19,948 15,462 Proportional adjusted EBITDA for equity method investees(1) 16,336 14,848 Adjustments related to capital reimbursement activity(2) (5,655) (3,876) Realized gain on swaps (391) (1,784) Other, net(3) 2,327 14,039 Less: Distributions from equity method investees 15,519 13,955 Noncash lease expense 1,554 3,897 Adjusted EBITDA $ 114,891 $ 118,600 Less: Cash interest paid 43,334 39,508 Cash paid for taxes — 265 Senior notes interest adjustment(4) — 4,935 Maintenance capital expenditures 7,876 8,007 Cash flow available for distributions(5) $ 63,681 $ 65,885 Less: Growth capital expenditures 36,394 38,989 Investment in equity method investee 6,508 3,063 Distributions on Subsidiary Series A Preferred Units — 3,257 Free Cash Flow $ 20,779 $ 20,576

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Rockies Segment Quarterly Detail (1) Segment adjusted EBITDA is a non-GAAP financial measure. We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income (excluding interest income), (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to minimum volume commitments ("MVC") shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) share-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains. 39 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Revenues: Gathering services and related fees $ 15,302 $ 15,078 $ 16,045 $ 16,303 $ 16,394 $ 14,018 $ 14,718 $ 15,583 Natural gas, NGLs and condensate sales 47,733 47,618 54,824 58,774 66,234 64,646 69,782 79,716 Other revenues 4,615 2,713 4,918 5,242 4,435 7,518 1,604 4,588 Total revenues $ 67,650 $ 65,409 $ 75,787 $ 80,319 $ 87,063 $ 86,182 $ 86,103 $ 99,887 Costs and expenses: Cost of natural gas and NGLs 28,029 26,575 35,142 35,570 38,089 39,655 39,372 49,092 Operation and maintenance 12,088 12,690 12,697 16,877 16,897 15,808 16,536 17,152 Integration costs — — — — 65 — — (1,290) General and administrative 1,050 1,253 1,406 1,740 1,331 1,961 3,724 1,285 Depreciation and amortization 9,143 9,141 9,753 10,711 10,453 10,669 10,757 12,886 (Gain) loss on asset sales, net (6) — — — (6) — 15 (26) Long-lived asset impairment — 324 — 71 — 2,654 — — Total costs and expenses $ 50,304 $ 49,983 $ 58,998 $ 64,969 $ 66,829 $ 70,747 $ 70,404 $ 79,099 Add: Depreciation and amortization 9,143 9,141 9,753 10,711 10,453 10,669 10,757 12,886 Integration costs — — — — 65 — — (1,290) Adjustments related to capital reimbursement activity (1,645) (1,646) (1,714) (1,690) (1,747) (1,826) (2,001) (1,999) (Gain) loss on asset sales, net (6) — — — (6) — 15 (26) Long-lived asset impairment — 324 — 71 — 2,654 — — Other 12 — 41 793 — 900 1,905 — Segment adjusted EBITDA (1) $ 24,850 $ 23,245 $ 24,869 $ 25,235 $ 28,999 $ 27,832 $ 26,375 $ 30,359 Less: (-) Cash Paid for Capex 8,743 14,881 11,473 10,848 8,375 9,017 10,976 17,013 Segment adjusted EBITDA less Cash Paid for Capex $ 16,107 $ 8,364 $ 13,396 $ 14,387 $ 20,624 $ 18,815 $ 15,399 $ 13,346

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Rockies Segment Quarterly Detail (cont’d) 40 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Operating statistics: Average daily throughput (MMcf/d) 128 131 129 147 158 160 167 162 Average daily throughput (Mbbl/d) 70 68 74 78 72 66 64 68 DJ Well Connects 29 6 22 32 4 33 18 16 Williston Well Connects — 17 8 6 5 — 13 — Well Connects 29 23 30 38 9 33 31 16 Rockies Liquids Gathering services and related fees $ 11,495 $ 11,423 $ 11,703 $ 12,272 $ 12,204 $ 10,126 $ 9,239 $ 10,437 (+) Gathering fees in Cost of Natural Gas and NGLs 119 249 77 130 147 121 394 410 (-) MVC shortfall payments in gathering revenue — — — — — — — — (-) Adjustments related to capital reimbursement activity 148 124 124 124 124 123 124 124 Adjusted Gathering services and related fees (1) $ 11,466 $ 11,548 $ 11,657 $ 12,278 $ 12,227 $ 10,123 $ 9,509 $ 10,724 (/) Volume throughput (Mbbl) (2) 6,440 6,256 6,660 7,098 6,624 6,072 5,760 6,188 Implied Gathering Rate ($ / Bbl) (3) $ 1.78 $ 1.85 $ 1.75 $ 1.73 $ 1.85 $ 1.67 $ 1.65 $ 1.73 Rockies Natural Gas and Other Gathering services and related fees $ 3,807 $ 3,655 $ 4,342 $ 4,031 $ 4,190 $ 3,893 $ 5,479 $ 5,146 (+) Gathering fees in Cost of Natural Gas and NGLs 13,336 14,357 13,202 14,144 15,544 14,684 15,086 15,183 (-) MVC shortfall payments in gathering revenue 426 458 572 (9) 2 — 183 44 (-) Adjustments related to capital reimbursement activity 1,497 1,522 1,590 1,566 1,624 1,703 1,878 1,875 Adjusted Gathering services and related fees (1) $ 15,220 $ 16,032 $ 15,382 $ 16,618 $ 18,108 $ 16,874 $ 18,504 $ 18,410 (/) Volume throughput (MMcf) (2) 11,776 12,052 11,610 13,377 14,536 14,720 15,030 14,739 Implied Gathering Rate ($ / Mcf) (3) $ 1.29 $ 1.33 $ 1.32 $ 1.24 $ 1.25 $ 1.15 $ 1.23 $ 1.25 Net margin: Natural gas, NGLs and condensate sales $ 47,733 $ 47,618 $ 54,824 $ 58,774 $ 66,234 $ 64,646 $ 69,782 $ 79,716 (+) Other revenues 4,615 2,713 4,918 5,242 4,435 7,518 1,604 4,588 (-) Gathering fees in Cost of Natural Gas and NGLs 13,455 14,606 13,279 14,274 15,691 14,805 15,480 15,594 (-) Cost of natural gas and NGLs 28,029 26,575 35,142 35,570 38,089 39,655 39,372 49,092 Net Margin (4) $ 10,864 $ 9,150 $ 11,321 $ 14,172 $ 16,888 $ 17,705 $ 16,533 $ 19,618 (/) Volume throughput (MMcf) (2) 11,776 12,052 11,610 13,377 14,536 14,720 15,030 14,739 Implied Net Margin ($ / Mcf) (5) $ 0.92 $ 0.76 $ 0.98 $ 1.06 $ 1.16 $ 1.20 $ 1.10 $ 1.33 (1) Represents gathering services and related fees, plus gathering fees in cost of natural gas and NGLs, less MVC shortfall payments in gathering revenue, less adjustments related to capital reimbursement activity. (2) Represents volume throughput multiplied by the number of days in the period. (3) Represents adjusted gathering services and related fees divided by volume throughput. (4) Represents Natural gas, NGLs and condensate sales, plus other revenue, less gathering fees in cost of natural gas and NGLs, less cost of natural gas and NGLs. (5) Represents net margin divided by volume throughput.

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Mid-Con Segment Quarterly Detail (1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in Other revenues (2) Segment adjusted EBITDA is a non-GAAP financial measure. We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income (excluding interest income), (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to minimum volume commitments ("MVC") shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) share-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains. 41 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Revenues: Gathering services and related fees $ 11,107 $ 17,494 $ 32,377 $ 32,245 $ 33,548 $ 33,368 $ 31,585 $ 34,057 Natural gas, NGLs and condensate sales — 1,464 3,597 6,939 4,526 3,492 3,295 3,950 Other revenues (1) 3,142 2,890 2,193 2,239 2,195 2,513 2,230 1,480 Total revenues $ 14,249 $ 21,848 $ 38,167 $ 41,423 $ 40,269 $ 39,373 $ 37,110 $ 39,487 Costs and expenses: Cost of natural gas and NGLs — 129 — 95 (86) — — — Operation and maintenance 6,546 8,384 15,193 15,682 15,817 16,984 16,919 17,283 Integration costs — — 590 746 706 639 15 533 General and administrative 321 382 425 694 548 649 611 577 Depreciation and amortization 3,841 5,286 7,823 8,400 8,616 8,550 8,747 8,762 (Gain) loss on asset sales, net — 39 — — — (195) — — Long-lived asset impairment — — — — — — — — Total costs and expenses $ 10,708 $ 14,220 $ 24,031 $ 25,617 $ 25,601 $ 26,627 $ 26,292 $ 27,155 Add: Depreciation and amortization (1) 4,076 5,520 8,058 8,634 8,851 8,784 8,982 8,996 Integration costs — — 590 746 706 639 15 533 Adjustments related to capital reimbursement activity (339) (340) (332) (336) (669) (510) (498) (501) (Gain) loss on asset sales, net — 39 — — — (195) — — Long-lived asset impairment — — — — — — — — Other — — 5 50 — — 10 1 Segment adjusted EBITDA 7,278 12,847 22,457 24,900 23,556 21,464 19,327 21,361 Less: (-) Cash Paid for Capex 161 626 7,222 14,504 13,484 8,992 7,320 6,807 Segment adjusted EBITDA less Cash Paid for Capex 7,117 12,221 15,235 10,396 10,072 12,472 12,007 14,554

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Mid-Con Segment Quarterly Detail (cont’d) 42 (1) Represents gathering services and related fees, plus gathering fees in cost of natural gas and NGLs, less MVC shortfall payments in gathering revenue, less adjustments related to capital reimbursement activity. (2) Represents volume throughput multiplied by the number of days in the period. (3) Represents adjusted gathering services and related fees divided by volume throughput. (4) Represents Natural gas, NGLs and condensate sales, plus other revenue, less gathering fees in cost of natural gas and NGLs, less cost of natural gas and NGLs. (5) Represents net margin divided by volume throughput. 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Operating statistics: Average daily throughput (MMcf/d) 255 329 488 502 508 489 476 523 Barnett Well Connects 9 — 5 6 6 — — 17 Arkoma Well Connects — — 6 3 6 6 6 3 Well Connects 9 — 11 9 12 6 6 20 Implied gathering rate: Gathering services and related fees $ 11,107 $ 17,494 $ 32,377 $ 32,245 $ 33,548 $ 33,368 $ 31,585 $ 34,057 (-) MVC shortfall payments in gathering revenue — 40 — — — — — — (-) Adjustments related to capital reimbursement activity 339 340 332 336 669 510 498 501 Adjusted Gathering services and related fees (1) $ 10,768 $ 17,114 $ 32,045 $ 31,909 $ 32,879 $ 32,858 $ 31,087 $ 33,556 (/) Volume throughput (MMcf) (2) 23,460 30,268 43,920 45,682 46,736 44,988 42,840 47,593 Implied Gathering Rate ($ / Mcf) (3) $ 0.46 $ 0.57 $ 0.73 $ 0.70 $ 0.70 $ 0.73 $ 0.73 $ 0.71 Net margin: Natural gas, NGLs and condensate sales $ — $ 1,464 $ 3,597 $ 6,939 $ 4,526 $ 3,492 $ 3,295 $ 3,950 (+) Other revenues 3,142 2,890 2,193 2,239 2,195 2,513 2,230 1,480 (-) Cost of natural gas and NGLs — 129 — 95 (86) — — — Net Margin (4) $ 3,142 $ 4,225 $ 5,790 $ 9,083 $ 6,807 $ 6,005 $ 5,525 $ 5,430 (/) Volume throughput (MMcf) (2) 23,460 30,268 43,920 45,682 46,736 44,988 42,840 47,593 Implied Net Margin ($ / Mcf) (5) $ 0.13 $ 0.14 $ 0.13 $ 0.20 $ 0.15 $ 0.13 $ 0.13 $ 0.11

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Permian Segment Quarterly Detail (1) Includes our proportional share of adjusted EBITDA for Double E. We define proportional adjusted EBITDA for our equity method investees as the product of total revenues less total expenses, excluding impairments and other noncash income or expense items; multiplied by our ownership interest during the respective period. (2) Segment adjusted EBITDA is a non-GAAP financial measure. We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income (excluding interest income), (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to minimum volume commitments ("MVC") shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) share-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains. (3) Gross basis, represents 100% of volume throughput and MVC quantities for Double E Pipeline, LLC. (4) Proportionate adjusted EBITDA for Double E divided by Summit ownership of 70%. (5) Represents MVC Quantities multiplied by the number of days in the period. (6) Represents implied Double E Pipeline, LLC divided by MVC Quantities. 43 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Revenues: Gathering services and related fees $ — $ — $ — $ — $ — $ — $ — $ — Natural gas, NGLs and condensate sales — — — — — — — — Other revenues 910 910 910 911 910 910 947 947 Total revenues $ 910 $ 910 $ 910 $ 911 $ 910 $ 910 $ 947 $ 947 Costs and expenses: Cost of natural gas and NGLs — — — — — — — — Operation and maintenance — — — — — — — — General and administrative 24 52 44 56 54 43 88 48 Transaction costs — — — — — 27 — — Depreciation and amortization — — — — — — — — (Gain) loss on asset sales, net — — — — — — — — Long-lived asset impairment — — — — — — — — Total costs and expenses $ 24 $ 52 $ 44 $ 56 $ 54 $ 70 $ 88 $ 48 Add: Depreciation and amortization — — — — — — — — Adjustments related to capital reimbursement activity — — — — — — — — (Gain) loss on asset sales, net — — — — — — — — Long-lived asset impairment — — — — — — — — Proportional adjusted EBITDA for Double E (1) 7,586 6,935 7,404 7,445 7,819 7,868 7,871 8,465 Other — — — — — 27 — — Segment adjusted EBITDA 8,472 7,793 8,270 8,300 8,675 8,735 8,730 9,364 Less: (-) Investments in Double E Equity Method Investee 989 2,449 2,488 575 753 — — — Segment adjusted EBITDA less Investments in Double E Equity Method (2) 7,483 5,344 5,782 7,725 7,922 8,735 8,730 9,364 Operating statistics: Average daily throughput (MMcf/d) - 8/8ths (3) 661 613 664 682 712 861 805 859 MVC Quantities (MMBtu/d) - 8/8ths (3) 1,009 1,009 1,069 1,069 1,069 1,069 1,115 1,115 Implied Double E economics: Proportional adjusted EBITDA for Double E $ 7,586 $ 6,935 $ 7,404 $ 7,445 $ 7,819 $ 7,868 $ 7,871 $ 8,465 (/) SMC Ownership of Double E 70% 70% 70% 70% 70% 70% 70% 70% Implied Double E Pipeline, LLC (4) $ 10,837 $ 9,907 $ 10,577 $ 10,636 $ 11,170 $ 11,240 $ 11,244 $ 12,093 (/) MVC Quantities (MMBtu) (5) 92,790 92,790 96,177 97,245 98,314 98,314 100,350 101,465 Implied EBITDA per MVC Quantity ($ / MMBtu) (6) $ 0.12 $ 0.11 $ 0.11 $ 0.11 $ 0.11 $ 0.11 $ 0.11 $ 0.12

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Piceance Segment Quarterly Detail 44 (1) Segment adjusted EBITDA is a non-GAAP financial measure. We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income (excluding interest income), (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to minimum volume commitments ("MVC") shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) share-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains. (2) Represents gathering services and related fees, less MVC shortfall payments in gathering revenue, less adjustments related to capital reimbursement activity (3) Represents volume throughput multiplied by the number of days in the period (4) Represents adjusted gathering services and related fees divided by volume throughput (5) Represents Natural gas, NGLs and condensate sales, plus other revenue, less cost of natural gas and NGLs (6) Represents net margin divided by volume throughput 2024 2025 2026 ($s in 000s, unless otherwise noted) Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Revenues: Gathering services and related fees $ 17,604 $ 17,061 $ 15,743 $ 15,634 $ 15,417 $ 14,585 $ 13,267 $ 13,060 Natural gas, NGLs and condensate sales 510 651 906 632 319 170 575 450 Other revenues 1,492 1,138 1,184 1,298 2,905 1,074 1,140 1,182 Total revenues $ 19,606 $ 18,850 $ 17,833 $ 17,564 $ 18,641 $ 15,829 $ 14,982 $ 14,692 Costs and expenses: Cost of natural gas and NGLs 219 243 292 250 134 (2) 2 — Operation and maintenance 6,011 6,529 5,642 6,678 5,648 5,192 4,760 5,379 General and administrative 319 366 322 328 337 300 324 321 Depreciation and amortization 10,524 10,491 10,550 10,547 9,379 7,093 6,877 6,850 (Gain) loss on asset sales, net — — — — 126 561 14 — Long-lived asset impairment — — — — — — — — Total costs and expenses $ 17,073 $ 17,629 $ 16,806 $ 17,803 $ 15,624 $ 13,144 $ 11,977 $ 12,550 Add: Depreciation and amortization 10,524 10,491 10,550 10,547 9,379 7,093 6,877 6,850 Adjustments related to capital reimbursement activity (298) 10 70 70 (63) (276) (326) (330) (Gain) loss on asset sales, net — — — — 126 561 14 — Long-lived asset impairment — — — — — — — — Other 72 70 139 96 50 (58) — — Segment adjusted EBITDA(1) 12,831 11,792 11,786 10,474 12,509 10,005 9,570 8,662 Less: (-) Cash Paid for Capex 1,405 83 1,090 110 331 243 239 524 Segment adjusted EBITDA less Cash Paid for Capex 11,426 11,709 10,696 10,364 12,178 9,762 9,331 8,138 Operating statistics: Average daily throughput (MMcf/d) 284 277 266 263 259 245 227 214 Well Connects — — — — — — — — Implied gathering rate: Gathering services and related fees $ 17,604 $ 17,061 $ 15,743 $ 15,634 $ 15,417 $ 14,585 $ 13,267 $ 13,060 (-) MVC shortfall payments in Gathering Revenue 4,998 4,985 4,233 4,219 4,192 4,289 3,890 4,200 (-) Adjustments related to capital reimbursement activity 298 (10) (70) (70) 63 276 326 330 Adjusted Gathering services and related fees (2) $ 12,308 $ 12,086 $ 11,580 $ 11,485 $ 11,162 $ 10,020 $ 9,051 $ 8,530 (/) Volume throughput (MMcf) (3) 26,128 25,484 23,940 23,933 23,828 22,540 20,430 19,474 Implied Gathering Rate ($ / Mcf) (4) $ 0.47 $ 0.47 $ 0.48 $ 0.48 $ 0.47 $ 0.44 $ 0.44 $ 0.44 Net margin: Natural gas, NGLs and condensate sales $ 510 $ 651 $ 906 $ 632 $ 319 $ 170 $ 575 $ 450 (+) Other revenues 1,492 1,138 1,184 1,298 2,905 1,074 1,140 1,182 (-) Cost of natural gas and NGLs 219 243 292 250 134 (2) 2 — Net Margin (5) $ 1,783 $ 1,546 $ 1,798 $ 1,680 $ 3,090 $ 1,246 $ 1,713 $ 1,632 (/) Volume throughput (MMcf) (3) 26,128 25,484 23,940 23,933 23,828 22,540 20,430 19,474 Implied Net Margin ($ / Mcf) (6) $ 0.07 $ 0.06 $ 0.08 $ 0.07 $ 0.13 $ 0.06 $ 0.08 $ 0.08

Slides