Summit Midstream Corp: Form 10-Q for the period ended Mar 31, 2026

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.

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.

(In thousands)

(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.

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 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.

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.

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, further increases in inflation 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.

Impact of increases in interest rates. Increases in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of existing and any additional financing. Since March 2022, the Federal Reserve has raised its target range for the federal funds rate multiple times and the timing of any potential further increases or decreases remains uncertain. As of March 31, 2026, we had approximately $825.0 million principal of fixed-rate debt, $116.0 million outstanding under our variable rate Amended and Restated ABL Facility and $340.0 million outstanding under the variable rate New Permian Transmission Facility. (See Note 7 - Debt for additional information.) As of March 31, 2026, we had $100.0 million of interest rate exposure hedged to offset the impact of changes in interest rates on our New Permian Transmission Facility.

Results of Operations

Consolidated Overview for the Three Months Ended March 31, 2026 and 2025

The following table presents certain consolidated financial and operating data.

(In thousands)

(1) Excludes volume throughput for Double E. For additional information, see the Permian section herein under the caption “Segment Overview for the Three Months Ended March 31, 2026 and 2025”.

Volumes – Gas. Natural gas throughput volumes decreased 13 MMcf/d for the three months ended March 31, 2026 compared to the three months ended March 31, 2025, reflecting:

• a volume throughput increase of 38 MMcf/d for the Rockies segment.
• a volume throughput decrease of 12 MMcf/d for the Mid-Con segment.
• a volume throughput decrease of 39 MMcf/d for the Piceance segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Rockies segment decreased for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to natural production declines, offset by 11 new well connections that came online subsequent to March 31, 2025.

For additional information on volumes, see the “Segment Overview for the Three Months Ended March 31, 2026 and 2025” section herein.

Revenues. Total revenues increased $6.4 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025, comprised of a $14.3 million increase in natural gas, NGLs and condensate sales, a $4.6 million decrease in gathering services and related fees and a $3.3 million decrease in other revenue.

Gathering Services and Related Fees. Gathering services and related fees decreased $4.6 million compared to the three months ended March 31, 2025, primarily reflecting:

• a $1.3 million decrease in the Rockies;
• a $0.8 million decrease in the Mid-Con; and
• a $2.5 million decrease in the Piceance, primarily due to decreased volume throughput.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased $14.3 million compared to the three months ended March 31, 2025, primarily reflecting:

• a $15.0 million increase in the Rockies, primarily reflecting new well connections and additional throughput in connection with the Moonrise Acquisition, partially offset by natural production declines.

Costs and Expenses. Total costs and expenses increased $4.7 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $3.9 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025 primarily related to the Moonrise Acquisition in late March 2025.

Operation and Maintenance. Operation and maintenance expense increased $4.7 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025 primarily as a result of the Moonrise Acquisition which closed in March 2025.

General and administrative. General and administrative expense increased $1.3 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025 primarily as a result of increased employee salaries and benefits expense and a $2.0 million expense related to the settlement of an outstanding commercial dispute. These increases were partially offset by lower contract labor expense. For the three months ended March 31, 2026 and 2025, general and administrative expenses include $3.0 million and $2.4 million of noncash stock-based compensation, respectively.

Depreciation and amortization. Depreciation and amortization expense decreased $1.8 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to certain Piceance segment assets that were disposed of during the quarterly period ended September 30, 2025.

Transaction costs. During the three months ended March 31, 2025, transaction costs primarily relate to the Moonrise Acquisition and Tall Oak Acquisition.

Acquisition integration costs. Acquisition and integration costs during the three months ended March 31, 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 increased $2.5 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025 primarily related to $1.6 million of increased debt issuance cost amortization, primarily related to the write off of the remaining unamortized debt issuance costs on the Legacy Permian Transmission Credit Facilities and $1.1 million of increased interest expense related to the issuance of the Additional 2029 Secured Notes.

Income Tax. For the three months ended March 31, 2026, the Company recorded a tax benefit of $1.0 million. Our effective tax rate was different from the U.S. federal statutory income tax rate primarily due to the net income allocated to the noncontrolling interest, tax benefits related to stock-based compensation, and nondeductible executive compensation.

Segment Overview for the Three Months Ended March 31, 2026 and 2025

Rockies.

Volume throughput for our Rockies reportable segment follow:

Natural gas. Natural gas volume throughput increased 29% for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily reflecting 100 new well connections that came online subsequent to March 31, 2025 and additional throughput in connection with the Moonrise Acquisition, partially offset by natural production declines.

Liquids. Liquids volume throughput decreased 14% for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to natural production declines, partially offset by 11 new well connections that came online subsequent to March 31, 2025.

Financial data for our Rockies reportable segment follows.

(In thousands)

* Not considered meaningful

Three months ended March 31, 2026. Segment adjusted EBITDA increased $1.5 million, compared to the three months ended March 31, 2025, primarily as a result of increased throughput described above, partially offset by lower freshwater sales.

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

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

33

Permian.

Volume throughput for our Permian reportable segment follow:

Volume throughput for Double E increased 21% for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, as a result of increased throughput volumes from its customers.

The following table presents the MVC quantities (i) that Double E’s shippers have contracted for under firm transportation service agreements and related negotiated rate agreements and (ii) three new precedent agreements for projects not yet placed in service. These precedent agreements are expected to require between $45.0 and $50.0 million of capital investment by Summit Permian Transmission, all of which is expected to be funded with the New Permian Transmission Facility.

34

Financial data for our Permian reportable segment follow:

(In thousands)

Three months ended March 31, 2026. Segment adjusted EBITDA increased $0.5 million, compared to the three months ended March 31, 2025, primarily as a result of an increase in proportional adjusted EBITDA from our equity method investment in Double E.

Mid-Con.

Volume throughput for our Mid-Con reportable segment follow:

Volume throughput decreased for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily as a result of natural production declines, partially offset by 33 new well connections that came online subsequent to March 31, 2025.

Financial data for our Mid-Con reportable segment follow:

(In thousands)

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

Three months ended March 31, 2026. Segment adjusted EBITDA decreased $3.1 million, compared to the three months ended March 31, 2025, primarily as a result of lower volume throughput discussed above as well as a temporary increase in field compression equipment expense.

Piceance.

Volume throughput for our Piceance reportable segment follow:

Volume throughput decreased 15% for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily as a result of natural production declines and an 8MMcf/d decrease from shut-in impacts during the quarter ended March 31, 2026.

Financial data for our Piceance reportable segment follow:

(In thousands)

*Not considered meaningful

Three months ended March 31, 2026. Segment adjusted EBITDA decreased $2.2 million, compared to the three months ended March 31, 2025 primarily as a result of lower volume throughput discussed above as well as contractual step-downs of existing commercial agreements.

Corporate and Other Overview for the Three Months Ended March 31, 2026 and 2025

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, and interest expense. Corporate and Other includes intercompany eliminations.

(In thousands)

General and administrative. For the three months ended March 31, 2026, general and administrative expenses attributable to Corporate and Other decreased by $1.3 million compared to the three months ended March 31, 2025, primarily due to lower fees associated with transition services incurred in 2025 for the Tall Oak acquisition, offset by increased employee salaries and benefit expense. For the three months ended March 31, 2026 and 2025, general and administrative expenses included $3.0 million and $2.4 million of noncash stock-based compensation, respectively.

Transaction costs. Transaction costs during the three months ended March 31, 2025 primarily relate to the Moonrise Acquisition and Tall Oak Acquisition.

Acquisition integration costs. Acquisition and integration costs during the three months ended March 31, 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 increased $2.5 million for the three months ended March 31, 2026, compared to three months ended March 31, 2025, primarily related to $1.6 million of increased debt issuance cost amortization, primarily related to the write off of the remaining unamortized debt issuance costs on the Legacy Permian Transmission Credit Facilities and $1.1 million of increased interest expense related to the issuance of the Additional 2029 Secured Notes.

How We Evaluate Our Operations

We currently conduct and report our operations in the midstream energy industry through four reportable segments: Rockies, Permian, Mid-Con, and Piceance. 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 15 - 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 three months ended March 31, 2026.

Summit Midstream Corporation Tax Structure. We operate the Company in an Up-C tax structure whereby the Company owned 68% of SMLP as of March 31, 2026 and Tall Oak Parent owned the remaining 32% of SMLP as a noncontrolling interest. If on March 31, 2026, Tall Oak Parent converted their 6.5 million SMLP Partnership Common Units and 6.5 million Class B shares 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 unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the “How We Evaluate Our Operations” section of MD&A included in the 2025 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods. (See 2 - Summary of Significant Accounting Policies and Recently Issued Accounting Standards Applicable to the Company for additional information.)

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, 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 Amended and Restated ABL Facility and New Permian Transmission 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 March 31, 2026, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $2.7 million, and (ii) letters of credit outstanding against our New Permian Transmission Facility aggregating to $7.0 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 March 31, 2026, the First Lien Net Leverage Ratio (as defined in the Amended and Restated ABL Agreement) and the Interest Coverage Ratio were 0.35:1.00 and 2.74:1.00, respectively.

Amended and Restated ABL Facility. As of March 31, 2026, 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), and (c) any date on which the aggregate Commitments terminate thereunder. As of March 31, 2026, there was $116.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $381.3 million after giving effect to the issuance thereunder of $2.7 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 Legacy 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.

Material Transactions Impacting Liquidity. As discussed elsewhere in Item 2 of this document, we completed the following material transactions during the three months ended March 31, 2026 that impacted, or will impact, our current and future liquidity and payment obligations.

• Refinancing of Legacy Permian Transmission Credit Facilities. 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.
• Redemption of Subsidiary Series A Preferred Units. In March 2026, in connection with the refinancing of our Legacy Permian Transmission Credit Facilities, we redeemed in full all outstanding Subsidiary Series A Preferred Units with a cash payment of $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 a $46.3 million cash payment for accrued and unpaid dividends owed from March 15, 2020 to December 14, 2024.
• Equity issuance with a related party. In March 2026, 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.
• Payment of Related party – Tall Oak deferred earn-out. In March 2026, we settled our deferred earn-out obligation to Tall Oak Parent in full for a cash payment of $22.0 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 and cash equivalents were as follow:

(In thousands)

40

Operating activities. Details of operating cash flows follow:

Operating activity cash flows during the three months ended March 31, 2026 primarily reflected:

• a net loss of $3.2 million plus positive adjustments of $35.7 million for non-cash operating items; and
• a $25.6 million outflow due to changes in working capital accounts.

Operating activity cash flows during the three months ended March 31, 2025 primarily reflected:

• a net income of $4.6 million plus adjustments of $29.4 million for non-cash operating items; and
• an $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 three months ended March 31, 2026 primarily reflected:

• $19.3 million of cash outflows for capital expenditures.

Investing activity cash flows during the three months ended March 31, 2025 primarily reflected:

• $70.0 million of cash outflows from cash consideration paid for the acquisition of Moonrise, net of cash acquired in the transaction; and
• $20.6 million of cash outflows for capital expenditures.

Financing activities. Details of financing activities follow:

Financing activity cash flows during the three months ended March 31, 2026 primarily reflected:

• $340.0 million of cash inflows for borrowings under the New Permian Transmission Credit Facility;
• $78.0 million of cash inflows for borrowings on the Amended and Restated ABL Facility;
• $41.5 million of cash inflows for proceeds from related party shares issued for cash; partially offset by
• $143.2 million of cash outflows for redemption of our Subsidiary Series A Preferred Units;
• $117.0 million of cash outflows for repayments on the Legacy Permian Transmission Term Loan;
• $75.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;
• $49.4 million of cash outflows for Distributions on Series A Preferred Stock; and
• $21.3 million of cash outflows for the related party settlement of the Tall Oak earn-out.

Financing activity cash flows during the three months ended March 31, 2025 primarily reflected:

• $250.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;
• $4.0 million of cash outflows for repayments on the Legacy Permian Transmission Term Loan;
• $258.4 million of cash inflows from the issuance of the Additional 2029 Secured Notes; and
• $90.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.

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.

For the three months ended March 31, 2026, cash paid for capital expenditures totaled $19.3 million which included $3.7 million of maintenance capital expenditures. For the three months ended March 31, 2026, we did not make any contributions to Double E.

We rely primarily on internally generated cash flows, our current 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 New Permian Transmission Facility, 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.

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.

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.

Off-Balance Sheet Arrangements

During the three months ended March 31, 2026, there were no material changes to the off-balance sheet obligations disclosed in our 2025 Annual Report.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no significant changes to our critical accounting estimates from those disclosed on 2025 Annual Report.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. 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 continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement 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. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Part II. Item 1A. Risk Factors included in this report.

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 report 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 others:

• 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 political or economic measures taken by various countries or OPEC and the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups;
• the extent and success of our customers’ drilling and completion efforts, as well as the quantity of natural gas, crude oil, freshwater deliveries, and produced water volumes produced within proximity of our assets;
• 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;
• 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;
• the current and potential future impact of pandemics on our business, results of operations, financial position, or cash flows;
• operational risks and hazards inherent in the transmission, gathering, compression, treating, and/or processing of natural gas, crude oil and produced water;
• our ability to comply with the terms of the agreements comprising the Global Settlement;
• 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 transmission, 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;
• the effects of litigation;
• interest rates;
• changes in general economic conditions; and
• certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common stock, Series A Preferred Stock and 2029 Secured Notes.

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.

Information About Us

Investors should note that we make available, free of charge on our website at www.summitmidstream.com (http://www.summitmidstream.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also post announcements, updates, events, investor information, and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein.

The SEC maintains a website at www.sec.gov (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

Interest Rate Risk

Our interest rate risk exposure, which is largely related to our indebtedness, has not changed materially since December 31, 2025, except for the following. In connection with the refinancing of the Legacy Permian Transmission Credit Facilities, our variable rate indebtedness increased by $223.0 million. Additionally, as of March 31, 2026, the notional amount of our interest rate swaps remained at approximately $100.0 million. As of March 31, 2026, we had approximately $825.0 million principal of fixed-rate debt, $116.0 million outstanding under our variable rate Amended and Restated ABL Facility and $340.0 million outstanding under the variable rate New Permian Transmission Facility. (See Note 7 - Debt for additional information.) While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Amended and Restated ABL Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the three months ended March 31, 2026, a hypothetical 1% increase (decrease) in interest rates on our variable rate debt would have increased (decreased) our interest expense by approximately $0.7 million, assuming no changes in amounts drawn or other variables under our Amended and Restated ABL Facility, Legacy Permian Transmission Term Loan, and New Permian Transmission Facility. For additional information, see the “Interest Rate Risk” section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2025 Annual Report and updates to our risk factors included herein.

Commodity Price Risk

We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and 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 and (iii) the sale of condensate we retain from certain gathering services in the Piceance segment. Our gathering agreements with certain Mid-Con customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, 2025. For additional information, see the “Commodity Price Risk” section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2025 Annual Report.

Under the direction of our Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of March 31, 2026 and (ii) no change in internal control over financial reporting occurred during the quarter ended March 31, 2026, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

The risk factors contained in Item 1A. Risk Factors of the 2025 Annual Report are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred.