Summit Midstream Corp (SMC)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of the Company and its subsidiaries for the periods since December 31, 2025. As a result, the following discussion should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the Company’s 2025 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in the section “Forward-Looking Statements.” Actual results may differ materially from those contained in any forward-looking statements.

Overview

We are a value-oriented company focused on developing, owning, and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental U.S.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating, and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con segment customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to the performance of certain commodity price indexes which are then added to the fixed gathering rates.

We also have indirect exposure to changes in commodity prices such that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.

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Table of Contents

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Three Months Ended March 31, 2026 and 2025” section included herein.

(1)See “Liquidity and Capital Resources” herein for additional information on capital expenditures.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

•Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the ongoing U.S. military operation in Iran, and the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups, the current Russia-Ukraine conflict, international sanctions against Russia, the U.S. military operation in Venezuela, and other sustained military campaigns;

•Natural gas, NGL, and crude oil supply and demand dynamics;

•Actions of OPEC and its allies, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls;

•Production from U.S. shale plays;

•General economic conditions, whether internationally, nationally, or in the regional and local market areas in

which we do business, including any future economic downturn, the imposition of tariffs or trade or other

economic sanctions, and political instability;

•Capital markets availability and cost of capital; and

•Inflation and shifts in operating costs.

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Table of Contents

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the “Trends and Outlook” section of MD&A included in the 2025 Annual Report.

2026 capital structure transactions. During the quarterly period ended March 31, 2026, we completed several transactions with counterparties that impacted our financial position and quarterly cash flows and will also impact future cash outflows for interest expense, dividends, and operating and financing activities.

•Legacy Permian Transmission Credit Facilities Refinancing. In March 2026, we completed a $440.0 million refinancing of our Legacy Permian Transmission Credit Facilities in the form of the New Permian Transmission Facility having a maturity in March 2031, bearing interest at SOFR plus 4.00% per annum. The New Permian Transmission Facility consists of $340.0 million in initial term loan commitments, $50.0 million in delayed draw commitments (with a commitment fee of 1.00% per annum) and a $50.0 million uncommitted incremental facility. In connection with the New Permian Transmission Facility, Summit Permian Transmission entered into a $7.0 million letter of credit arrangement.

•Redemption of Subsidiary Series A Preferred Units. In March 2026, in connection with the Legacy Permian Transmission Credit Facility Refinancing, we redeemed in full all outstanding Subsidiary Series A Preferred Units for $143.2 million.

•Cash settlement of unpaid dividends for Series A Preferred Units. In March 2026, we made a cash dividend payment to the holders of our Series A Preferred Units which included $46.3 million for accrued and unpaid dividends owed from March 15, 2020 to December 14, 2024.

•Equity issuance with a related party. On March 31, 2026, pursuant to a Securities Purchase Agreement (the “Purchase Agreement”), by and among the Company, SMLP and Tall Oak Parent, and solely for purposes of modifying certain existing registration rights as detailed in the Purchase Agreement, Connect Midstream, LLC, we issued and sold to Tall Oak Parent 1,351,351 shares of common stock of the Company in exchange for $41.5 million of cash proceeds, net of $0.5 million of issuance costs. The shares were issued at a price of $31.08 per share, which represented the “Minimum Price” in accordance with NYSE regulations. The shares are subject to a 6-month lock up period and other terms and conditions.

Capital structure optimization and portfolio management. We intend to continue to improve our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic transactions with the objective of increasing long-term shareholder value. This may include opportunistic acquisitions, divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. We believe that our current cash balance, internally generated cash flow, our Amended and Restated ABL Facility, the New Permian Transmission Facility, and access to debt or equity capital markets will be adequate to finance our strategic initiatives. To attain our overall corporate strategic objectives, we may conduct an asset divestiture, or divestitures, at a transaction valuation that is less than the net book value of the divested asset.

Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices. Although we operate solely in the U.S., certain events and conditions in foreign oil and natural gas producing countries, such as the ongoing U.S. military operation in Iran, and the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups, Russia’s invasion of Ukraine, and the recent change in Venezuela’s political leadership, could have potential effects on us, including, but not limited to, volatility in currencies and commodity prices, higher inflation, cost and supply chain pressures and availability and disruptions in banking systems and capital markets. As of the date of filing, there have been no material impacts to us.

Natural gas, NGL, and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation and increase in U.S. LNG exports. Over the next several years, we expect natural gas prices will support continued upstream industry activity by producers focused on natural gas production.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin, and given the current regulatory environment in Colorado, in rural parts of the DJ Basin where

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to inform the reader about matters affecting the financial condition and results of operations of the Company and its subsidiaries. As a result, the following discussion for the year ended December 31, 2025 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual Report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

Unless the context requires otherwise or unless otherwise noted, all references to “Summit Midstream,” the “Company,” “we,” “us,” “our” or like terms are to Summit Midstream Corporation (including its subsidiaries) for the periods after August 1, 2024, the date the Corporate Reorganization was consummated. For the periods prior to August 1, 2024, unless the context requires otherwise or unless otherwise noted, all reference to “Summit Midstream,” or the “Company” are to Summit Midstream Partners, LP. (including its subsidiaries).

Overview

We are a value-oriented company focused on developing, owning, and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental U.S.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating, and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con segment customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to the performance of certain commodity price indexes which are then added to the fixed gathering rates. During the year ended December 31, 2025, these additional activities accounted for approximately 48% of our total revenues.

We also have indirect exposure to changes in commodity prices such that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.

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The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein.

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(1)See “Liquidity and Capital Resources” herein and Note 18 - Segment Information to the consolidated financial statements for additional information on capital expenditures.

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Key Matters for the Year ended December 31, 2025. The following is a brief listing of significant developments and highlights for the fiscal year ended December 31, 2025, and up through the filing date of this Form 10-K. Additional information regarding these items may be found elsewhere in this Annual Report.

•Moonrise Acquisition. On March 10, 2025, we completed the acquisition of Moonrise Midstream, LLC (the “Moonrise Acquisition”) from Fundare Resources Company, LLC for approximately $90.0 million, consisting of (i) a $70.0 million cash payment and (ii) the issuance of 462,265 shares of our common stock. The Moonrise Acquisition expanded our existing footprint in the DJ Basin and provides our DJ Basin customers with additional processing capacity and flow assurance. The Moonrise Acquisition represents the continued execution of our consolidation efforts in the DJ Basin.

•Resumption of Series A Preferred Stock Dividend. On February 28, 2025, we announced that our Board of Directors approved the resumption of a quarterly cash dividend on our Series A Preferred Stock. During 2025, we paid $13.4 million of dividends on our Series A Preferred Stock and as of December 31, 2025, the Series A Preferred Stock had $46.6 million of cumulative unpaid dividends that must be repaid prior to the payment of a common stock dividend. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

•Integration of acquired businesses. We spent significant time throughout 2025 integrating both the Moonrise Acquisition and the Tall Oak Acquisition into our existing operations. Activities included conforming the acquired businesses to our operating policies and procedures and attaining acquisition synergies, including rationalizing compression equipment.

•Commercial success. During 2025, we executed several new commercial agreements with both existing and new customers, including a 10-year extension of a gathering agreement with a key customer in the Williston Basin and a new 15-year agreement with a key customer in the Williston Basin. Additionally, in 2025 Double E executed a new precedent agreement for 100 MMcf/d of firm capacity tied to an expansion of a processing plant located in Lea County, New Mexico. Subsequent to December 31, 2025, Double E (i) executed an agreement which includes 210 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2026, and an 11-year term and (ii) executed an agreement which includes 230 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2027, and over an 11-year term.

•Summit Permian Transmission and Permian Holdco Refinancing. In March 2026, we completed a $440.0 million refinancing of our Permian Transmission Credit Facilities in the form of the New Permian Transmission Facility with a maturity in March 2031. The New Permian Transmission Facility consists of $340.0 million in initial term loan commitments, $50.0 million in delayed draw commitments, and a $50.0 million uncommitted incremental facility. The use of proceeds of the New Permian Transmission Facility includes, among other things, repayment in full of the Permian Transmission Credit Facilities and redemption in full of the outstanding Subsidiary Series A Preferred Units. In connection with the New Permian Transmission Facility, Summit Permian Transmission entered into a $7.0 million letter of credit arrangement.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

•Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the ongoing U.S. military operation in Iran, the current Russia-Ukraine conflict, international sanctions against Russia, the U.S. military operation in Venezuela, and other sustained military campaigns;

•Natural gas, NGL and crude oil supply and demand dynamics;

•Actions of OPEC and its allies, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls;

•Production from U.S. shale plays;

•Capital markets availability and cost of capital; and

•Inflation and shifts in operating costs.

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Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Capital structure optimization and portfolio management. We intend to continue to improve our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic transactions with the objective of increasing long-term shareholder value. This may include opportunistic acquisitions, divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. We believe that our current cash balance, internally generated cash flow, our Amended and Restated ABL Facility, the New Permian Transmission Facility and access to debt or equity capital markets will be adequate to finance our strategic initiatives. To attain our overall corporate strategic objectives, we may conduct an asset divestiture, or divestitures, at a transaction valuation that is less than the net book value of the divested asset.

Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices. Although we operate solely in the U.S., certain events and conditions in foreign oil and natural gas producing countries, such as the ongoing U.S. military operation in Iran, Russia’s invasion of Ukraine, and the recent change in Venezuela’s political leadership, could have potential effects on us, including, but not limited to, volatility in currencies and commodity prices, higher inflation, cost and supply chain pressures and availability and disruptions in banking systems and capital markets. As of the date of filing, there have been no material impacts to us.

Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. The average spot price of natural gas increased by approximately 61% from 2024 to 2025, primarily due to increasing demand. The average daily Henry Hub Natural Gas Spot Price was $3.52 per MMBtu during 2025, compared with $2.19 per MMBtu during 2024. As of January 31, 2026, Henry Hub 12-month strip pricing closed at $7.71 per MMBtu. During 2025, the number of active natural gas drilling rigs in the continental U.S. increased from 102 in December 2024 to 125 in December 2025, according to Baker Hughes. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation and increase in U.S. LNG exports. Despite these decreases, over the next several years we expect natural gas prices will continue to support continued upstream industry activity by producers focused on natural gas production.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2025, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price average of $76.63 per barrel during 2024 decreasing to an average of $65.39 per barrel during 2025, representing a 15% decrease. As of January 31, 2026, West Texas Intermediate 12-month strip pricing closed at $60.26 per barrel. During 2025, the number of active crude oil drilling rigs in the continental U.S. decreased from 483 in December 2024 to 412 in December 2025, according to Baker Hughes. Despite these decreases, over the next several years we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin, and given the current regulatory environment in Colorado, in rural parts of the DJ Basin where we operate.

Despite improving fundamentals that should support additional development activities, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas.

Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance, Barnett, Bakken, Permian, and Arkoma Basin shale plays in which we operate. We believe that these long-term capital investments should support drilling activity in unconventional shale plays over the long term.

Rate of growth in production from U.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated from their underlying assets. Producers are experiencing increasing pressure from their investors to focus on returning capital and maximizing free cash flow versus re-investing that cash flow into development. In general, we expect our producer customers to maintain moderate completion and production activities across many of our systems relative to our previous expectations as a result of the commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow.

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Capital markets availability and cost of capital. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt and equity capital markets, to the extent necessary, to fund our future growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

The borrowings under our Amended and Restated ABL Facility, which have a variable interest rate, expose us to the risk of increasing interest rates.

Inflation and operating costs. The annual rate of inflation in the U.S. hit 6.5% in December 2022, one of the highest increases in more than three decades, as measured by the Consumer Price Index. While inflation has declined since the second half of 2022, declining to 2.7% in December 2025, further increases in inflation in 2026 could increase our operating costs and the overall cost of capital projects we undertake. While some of our fee arrangements escalate based on changes in price indexes, these fee escalations may not be sufficient to offset an increase in our expenditures. Furthermore, inflation may impact producers’ economic decision making, which in turn could impact their willingness to develop acreage in areas that are more susceptible to inflationary pressures and labor force shortages.

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How We Evaluate Our Operations

We currently conduct and report our operations in the midstream energy industry through four reportable segments: Rockies, Permian, Piceance, and Mid-Con. Each of our reportable segments provides midstream services in a specific geographic area and our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 18 - Segment Information to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance and we view these metrics as important factors in evaluating our profitability. These metrics include (i) throughput volume, (ii) revenues, (iii) operation and maintenance expenses, (iv) capital expenditures and (v) Segment Adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the year ended December 31, 2025.

During the year ended December 31, 2024, we divested of our Northeast operations, which consisted of midstream assets located in the Marcellus shale play and midstream assets located in the Utica shale play together with our equity method investment in Ohio Gathering that was focused on the Utica Shale.

Throughput Volume

The volume of (i) natural gas that we gather, compress, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.

As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of throughput is impacted by:

•successful drilling activity within our AMIs;

•the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;

•the number of new pad sites in our AMIs awaiting connections;

•our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and

•our ability to gather, treat and/or process production that has been released from commitments with our competitors.

We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day.

Revenues

Our revenues are primarily attributable to the volumes that we gather, compress, treat and/or process and the rates we charge for those services. A majority of our gathering and processing agreements are fee-based, which limits our direct exposure to fluctuations in commodity prices; however, certain of our contracts have rates that are directly impacted by commodity prices. We also have percent-of-proceeds arrangements with certain customers under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.

Certain of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs help us generate stable revenues and serve to mitigate the financial impact associated with declining volumes.

Operation and Maintenance Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.

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Our operation and maintenance expenses also include costs that are reimbursed by our customers, which are included in Other revenues.

Capital Expenditures

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities.

We categorize our capital expenditures as either:

•maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

•expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Segment Adjusted EBITDA

Segment Adjusted EBITDA is a supplemental financial measure used by management and by external users of our financial statements such as investors, commercial banks, research analysts, and others. Segment Adjusted EBITDA is used to assess:

•the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;

•the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and

•the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of MVC shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

Summit Midstream Corporation Tax Structure. We operate the Company in an Up-C tax structure whereby the Company owns 65% of SMLP as of December 31, 2025 and certain Tailwater Capital, LLC entities (“Tailwater Capital”) own the remaining 35% of SMLP as a noncontrolling interest. If Tailwater Capital converted their 6.5 million SMLP partnership units and 6.5 million Class B shares on December 31, 2025 for the Company’s common stock, the following adjustments would occur to the Company’s balance sheet and common shares outstanding.

Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the consolidated financial statements contained in Item 8. Financial Statements and Supplementary Data.

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Results of Operations

Consolidated Overview for the Years Ended December 31, 2025 and 2024

Below is a discussion of changes in our results of operations for 2025 compared to 2024. A discussion of changes in our results of operations for 2024 compared to 2023 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2024 as filed with the SEC on March 11, 2025.

The following table presents certain consolidated data and volume throughput for the years ended December 31, 2025 and 2024.

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*Not considered meaningful

(1)Excludes volume throughput for Ohio Gathering and Double E. For additional information, see the Northeast and Permian sections herein under the caption “Segment Overview for the Years Ended December 31, 2025 and 2024.”

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Volumes – Gas. Natural gas throughput volumes increased 42 MMcf/d for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting:

•a volume throughput increase of 21 MMcf/d for the Rockies segment;

•a volume throughput increase of 256 MMcf/d for the Mid-Con segment; offset by

•a volume throughput decrease of 33 MMcf/d for the Piceance segment;

•a volume throughput decrease of 202 MMcf/d for the Northeast segment.

Volumes – Liquids. Crude oil and produced water volume throughput for the Rockies segment increased 1 Mbbl/d for the year ended December 31, 2025 compared to the year ended December 31, 2024.

For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein.

Revenues. Total revenues increased $132.5 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 comprised of a $54.8 million increase in gathering services and related fees, a $70.0 million increase in natural gas, NGLs and condensate sales and a $7.6 million increase in Other revenues.

Gathering services and related fees. Gathering services and related fees increased $54.8 million compared to the year ended December 31, 2024, primarily reflecting:

•a $85.9 million increase in the Mid-Con segment; offset by

•a $18.9 million decrease in the Northeast segment;

•a $11.7 million decrease in the Piceance segment;

•a $0.5 million decrease in the Rockies segment.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales revenue increased $70.0 million compared to the year ended December 31, 2024, primarily reflecting:

•a $53.9 million increase in the Rockies segment;

•a $16.8 million increase in the Mid-Con segment; offset by

•a $0.7 million decrease in the Piceance segment.

Costs and expenses. Total costs and expenses increased $18.2 million during the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting:

Cost of Natural Gas and NGLs. Costs of Natural Gas and NGL’s increased $34.1 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition and the Moonrise Acquisition.

Operation and Maintenance. Operation and maintenance expense increased $48.2 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition and the Moonrise Acquisition, partially offset by the disposition of our Mountaineer Midstream system.

General and administrative. General and administrative expense increased $5.5 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with acquisition diligence costs.

Depreciation and amortization. Depreciation and amortization expense increased $13.5 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to the Moonrise Acquisition and the Tall Oak Acquisition.

Transaction costs. During the year ended December 31, 2025, transaction costs primarily relate to the Moonrise Acquisition and Tall Oak Acquisition. In 2024, transaction costs primarily relate to the Tall Oak Acquisition and the Utica Sale.

Acquisition integration costs. Acquisition and integration costs in 2025 primarily relate to fees paid to third-party service providers to integrate the Tall Oak Acquisition and the Moonrise Acquisition into the Company’s operational platform.

Long-lived asset impairments. In 2025, we recognized impairments of $2.7 million, primarily related to the abandonment of aged pipeline that was no longer economical under the terms of our commercial arrangements. In 2024, we recognized impairments of $68.3 million primarily in connection with the Mountaineer Transaction.

Gain on sale of business. In 2024, we recognized a gain on sale of business primarily in connection with the disposition of the Utica midstream business in March of 2024.

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Gain on sale of equity method investment. In 2024, we recognized a gain on sale of equity method investment related to the disposition of our equity method investment, Ohio Gathering, in March of 2024.

Interest Expense. Interest expense decreased $20.7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to $44.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the Asset Sale Offer that occurred in July 2024 and May 2024, respectively, and $12.0 million of reduced interest expense due to the full repayment and discharge of the 2026 Unsecured Notes in June 2024. The decrease was partially offset by $49.1 million of increased borrowing costs in connection with the issuance of the 2029 Secured Notes in July 2024 and January 2025. See Note 9 – Debt to the consolidated financial statements for additional details. Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities.

Loss on early extinguishment of debt. Loss on early extinguishment of debt in 2024 is primarily related to amortization of debt issuance costs in connection with extinguishments of our 2026 Unsecured Notes, 2026 Secured Notes and 2025 Senior Notes.

Income taxes. For the year ended December 31, 2025, the Company recorded an income tax benefit of $0.5 million. The income tax benefit includes the impact from the allocation of income from SMLP to SMC as a result of the Company’s Up-C tax structure.

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Segment Overview for the Years Ended December 31, 2025 and 2024

Rockies.

Volume throughput for our Rockies reportable segment follows.

Natural gas. Natural gas volume throughput for the year ended December 31, 2025 increased 16% compared to the year ended December 31, 2024, primarily reflecting 99 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines.

Liquids. Liquids volume throughput for the year ended December 31, 2025 increased 1% compared to the year ended December 31, 2024, primarily reflecting 11 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines.

Financial data for our Rockies reportable segment follows.

_________________

* Not considered meaningful

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Year ended December 31, 2025. Segment Adjusted EBITDA increased $13.1 million compared to the year ended December 31, 2024 primarily as a result of margin mix and the Moonrise Acquisition.

The Company is providing additional financial and operational details below for its liquids related activities within its Rockies segment (in thousands):

The Company is providing below additional financial and operational details for its natural gas and other related activities within its Rockies segment (in thousands):

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Permian.

Volume throughput for our Permian reportable segment follows.

Volume throughput for Double E increased 27% compared to the year ended December 31, 2024, as a result of increased throughput volumes from its customers.

The following table presents the MVC quantities that Double E’s shippers have contracted for under firm transportation service agreements and related negotiated rate agreements, excluding three new precedent agreements totaling 100 MMcf/d, 210 MMcf/d and 230 MMcf/d of firm capacity. The 100 MMcf/d agreement has a 10-year term and is expected to be placed into service in the fourth quarter of 2026. The 210 MMcf/d agreement has an 11-year term and will be implemented in two tranches: 70 MMcf/d is expected to be placed into service in the fourth quarter of 2026, with the remaining 140 MMcf/d anticipated to be placed into service in the third quarter of 2028. The 230 MMcf/d agreement has over an 11-year term and will be implemented in three tranches: 100 MMcf/d is expected to be placed into service in the fourth quarter of 2027, 80 MMcf/d in the fourth quarter of 2028, and an additional 50 MMcfd in the second quarter of 2029.

Financial data for our Permian reportable segment follows.

_________________

* Not considered meaningful

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Year ended December 31, 2025. Segment Adjusted EBITDA increased $2.8 million compared to the year ended December 31, 2024 primarily as a result of an increase in Proportional Adjusted EBITDA from our equity method investment in Double E due to increased volumes described above.

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Mid-Con.

Volume throughput for our Mid-Con reportable segment follows.

Volume throughput increased 106% for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition, 38 wells that came online during 2025, and the resumption of previous production curtailments associated with reductions in commodity pricing, partially offset by natural production declines.

Financial data for our Mid-Con reportable segment follows.

_________________

*Not considered meaningful

(1)Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.

Year ended December 31, 2025. Segment Adjusted EBITDA increased $61.7 million compared to the year ended December 31, 2024 primarily as a result of the Tall Oak Acquisition and increased volume throughput discussed above.

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Piceance.

Volume throughput for our Piceance reportable segment follows.

Volume throughput for the year ended December 31, 2025 decreased 11% compared to the year ended December 31, 2024, primarily as a result of natural production declines.

Financial data for our Piceance reportable segment follows.

_________________

* Not considered meaningful

Year ended December 31, 2025. Segment Adjusted EBITDA decreased $7.9 million compared to the year ended December 31, 2024, primarily as a result of lower volume throughput discussed above as well as contractual step-downs.

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Northeast.

Volume throughput for the Northeast reportable segment follows.

On March 22, 2024, we completed the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering, and on May 1, 2024, we completed the disposition of our Mountaineer Midstream system.

Financial data for our Northeast reportable segment follows.

_________________

*Not considered meaningful

(1) SMLP recorded its financial results of its investment in Ohio Gathering on a one-month lag based on financial information available to us during the reporting period. With the divestiture of Ohio Gathering in March 2024, Proportional Adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024 ($2.5 million for March 1, 2024 - March 22, 2024).

Year ended December 31, 2025. Segment Adjusted EBITDA decreased $30.6 million compared to the year ended December 31, 2024, as the result of the sale of our Mountaineer Midstream system and the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering.

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Corporate and Other Overview for the Years Ended December 31, 2025 and 2024

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, transaction costs, acquisition integration costs, interest expense, and losses on early extinguishment of debt. Corporate and Other includes intercompany eliminations.

_________________

* Not considered meaningful

General and administrative. For the year ended December 31, 2025, general and administrative expense attributable to Corporate and Other increased by $3.0 million compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with the evaluation of acquisitions. For the year ended December 31, 2025, general and administrative costs include $7.8 million of noncash stock-based compensation and $1.7 million of severance expense. For the year ended December 31, 2024, general and administrative expenses include $8.6 million of noncash stock-based compensation and $0.1 million of severance expense.

Transaction costs. During the year ended December 31, 2025, transaction costs primarily relate to the Moonrise Acquisition and the Tall Oak Acquisition. In 2024, transaction costs primarily relate to the Tall Oak Acquisition and Utica Sale.

Acquisition integration costs. Acquisition and integration costs in 2025 primarily relate to fees paid to third-party service providers to integrate the Tall Oak Acquisition and the Moonrise Acquisition into the Company’s operational platform.

Interest Expense. Interest expense decreased $20.7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to $44.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the Asset Sale Offer that occurred in July 2024 and May 2024, respectively, and $12.0 million of reduced interest expense due to the full repayment and discharge of the 2026 Unsecured Notes in June 2024. The decrease was partially offset by $49.1 million of increased borrowing costs in connection with the issuance of the 2029 Secured Notes in July 2024 and January 2025.

See Note 9 – Debt to the consolidated financial statements for additional details. Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities.

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Liquidity and Capital Resources

We rely primarily on internally generated cash flows as well as our current cash balance and external financing sources, including commercial bank borrowings, the issuance of debt, equity, and preferred equity securities, and proceeds from potential asset divestitures, to fund our capital expenditures. We believe that our Amended and Restated ABL Facility and Permian Transmission Credit Facility, together with internally generated cash flows, current cash balance and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months, and based on current expectations, the long-term, without adversely impacting our liquidity.

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2025, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $0.8 million and (ii) letters of credit outstanding against our Permian Transmission Credit Facilities aggregating to $13.0 million. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.

We are in compliance with all covenants contained in the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and the New Permian Transmission Facility. The Amended and Restated ABL Facility requires that Summit Holdings not permit (i) the First Lien Net Leverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be greater than 2.50:1.00, or (ii) the Interest Coverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be less than 2.00:1.00. As of December 31, 2025, the First Lien Net Leverage Ratio was 0.48:1.00 and the Interest Coverage Ratio was 2.70:1.00. Beginning on June 30, 2026, the New Permian Transmission Facility will require Summit Permian Transmission to meet certain minimum debt service coverage ratios and, beginning on March 31, 2027, certain maximum total debt to EBITDA ratios.

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Amended and Restated ABL Facility. Concurrently with the issuance of the 2029 Secured Notes, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with SMLP, consisting of a $500.0 million asset-based revolving credit facility. As of December 31, 2025, the Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million (and, for the avoidance of doubt, once the Amended and Restated ABL Termination Date occurs it may not be unwound as a result of Liquidity (as defined in the Amended and Restated ABL Agreement) increasing on a subsequent date), or (c) any date on which the aggregate Commitments terminate thereunder. As of December 31, 2025, there was $113.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $385.7 million after giving effect to certain adjustments that are primarily related to the issuance of $0.8 million of outstanding but undrawn irrevocable standby letters of credit.

New Permian Transmission Facility. On March 16, 2026, Summit Permian Transmission completed a $440.0 million refinancing of the Permian Transmission Credit Facilities in the form of a new term loan facility (the “New Permian Transmission Facility”) bearing interest at SOFR plus 4.00% per annum and with a maturity in March 2031. The New Permian Transmission Facility consists of $340.0 million in initial term loan commitments, $50.0 million in delayed draw commitments (with a commitment fee of 1.00% per annum) and a $50.0 million uncommitted incremental facility. The use of proceeds of the New Permian Transmission Facility includes, among other things, repayment in full of the Permian Transmission Credit Facilities and redemption in full of the Subsidiary Series A Preferred Units. In connection with the New Permian Transmission Facility, Summit Permian Transmission entered into a $7.0 million letter of credit arrangement.

2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of 8.625% Senior Secured Second Lien Notes due 2029. The 2029 Secured Notes are guaranteed on a senior second-priority basis by Summit Midstream Corporation and certain of Summit Midstream Corporation’s existing and future subsidiaries and are secured on a second-priority basis by substantially the same collateral that is pledged for the benefit of the lenders under the Amended and Restated ABL Facility. On January 10, 2025, we issued an additional $250.0 million of the 2029 Secured Notes. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2025, the outstanding balance of the 2029 Secured Notes was $825.0 million.

Other. We may in the future use a combination of cash, secured or unsecured borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire or refinance our outstanding debt or Series A Preferred Stock through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to do so.

Cash Flows

The components of the net change in cash, cash equivalents and restricted cash were as follows:

Operating activities. Details of operating cash flows follow.

Operating activity cash flows during the year ended December 31, 2025 primarily reflected:

•a net loss of $1.9 million plus adjustments of $148.3 million for non-cash items; and

•a $12.8 million outflow due to changes in working capital accounts.

Operating activity cash flows during the year ended December 31, 2024 primarily reflected:

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•a net loss of $113.2 million plus adjustments of $192.9 million for non-cash items; and

•a $18.0 million outflow due to changes in working capital accounts.

Investing activities. Details of investing cash flows follow.

Investing activity cash flows during the year ended December 31, 2025 primarily reflected:

•$89.0 million of cash outflows for capital expenditures; and

• $70.0 million of cash outflows from the Moonrise Acquisition.

Investing activity cash flows during the year ended December 31, 2024 primarily reflected:

•$332.7 million of cash inflows from the proceeds of the sale Ohio Gathering;

•$292.3 million of cash inflows from the proceeds of the Utica Sale (excluding Ohio Gathering);

•$69.3 million of cash inflows from the proceeds of the Mountaineer Transaction;

•$4.4 million of cash inflows from the sale of compressor equipment; partially offset by

•$154.2 million of cash outflows from the Tall Oak Acquisition; and

•$53.6 million of cash outflows for capital expenditures.

Financing activities. Details of financing cash flows follow.

Financing activity cash flows during the year ended December 31, 2025 primarily reflected:

•$325.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;

•$12.3 million of cash outflows for repayments on the Permian Transmission Term Loan;

•$13.4 million of cash outflows for Distributions to Series A Preferred Shareholders;

•$6.5 million of cash outflows for Distributions to Subsidiary Series A Preferred Unitholders; offset by

•$258.4 million of cash inflows from the issuance of the Additional 2029 Secured Notes; and

•$133.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.

Financing activity cash flows during the year ended December 31, 2024 primarily reflected:

•$764.5 million of cash outflows for the 2026 Secured Notes Tender Offer and redemption of 2026 Secured Notes;

•$313.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;

•$209.5 million of cash outflows from the redemption of 2026 Unsecured Notes;

•$49.8 million of cash outflows from the redemption of 2025 Senior Notes;

•$23.8 million of cash outflows for debt extinguishment costs;

•$15.5 million of cash outflows for repayments on the Permian Transmission Term Loan;

•$13.6 million of cash outflows for the Excess Cash Flow Offer;

•$6.9 million of cash outflows for the 2026 Secured Notes Asset Sale Offer; offset by

•$565.8 million of cash inflows from the issuance of the 2029 Secured Notes; and

•$305.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.

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Contractual Obligations Update

The Company’s cash flows generated from operations are the primary source for funding various contractual obligations. The table below summarizes the Company’s major commitments as of December 31, 2025 through 2030 (in thousands):

(1)Amounts include an estimate for interest cost based on either the stated interest rate for fixed rate indebtedness or the interest rate in effect as of December 31, 2025 for variable rate indebtedness.

(2)Amounts include mandatory principal repayments of $21.3 million in 2026, which includes a $4.3 million principal payment that was made in January 2026 and $17.8 million in 2027. These amounts do not reflect the impact of the Summit Permian Transmission and Permian Holdco Refinancing (due March 2031). See Note 19 - Subsequent Events for additional information.

(3)Global Settlement amounts in the table exclude interest owed on the unpaid portion. See Note 10 - Commitments and Contingencies to the consolidated financial statements for additional details.

Capital Requirements

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement required that we categorize our capital expenditures as either:

•maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

•expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by Summit Midstream Corporation. For information on the Corporate Reorganization, see Note 1 - Organization, Corporate Reorganization, Business Operations and Presentation and Consolidation.

For the year ended December 31, 2025, cash paid for capital expenditures totaled $89.0 million which included $17.3 million of maintenance capital expenditures. For the year ended December 31, 2025, we contributed $3.8 million to Double E.

We rely primarily on internally generated cash flows, our cash balance as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity, and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our internally generated cash flows, current cash balance, our Amended and Restated ABL Facility and the Permian Transmission Credit Facilities, and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity.

We estimate that our 2026 capital program will range from $85.0 million to $105.0 million, including between $15.0 million and $20.0 million of maintenance capital expenditures. We estimate that we will make an additional investment in our Double E equity method investee of approximately $35.0 million.

There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and NGL industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.

Credit and Counterparty Concentration Risks

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits, and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

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Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a potential customer may not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

Critical Accounting Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.

Long-Lived Assets. Our long-lived assets consist of property, plant and equipment, and intangible assets that have been obtained by multiple business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information, asset specific information and other projections on the performance of the assets acquired (including an analysis of discounted cash flows which can involve assumptions on weighted average cost of capital and projected cash flows of the assets acquired). Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can and often do, differ from our estimates.

As of December 31, 2025, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net intangible assets with a carrying value of approximately $153.6 million. When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment, and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we would recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using a combination of approaches, including a market-based approach and an income-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary.

Business Combinations. In accordance with accounting guidance for business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed.

Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques,

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including discounted cash flows, and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. If actual results are materially different than the assumptions we used to determine fair value of the assets and liabilities acquired through a business combination, it is possible that adjustments to the carrying values of such assets and liabilities will have an impact on our net earnings.

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