Summit Midstream (SMC) Risk Analysis

We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA. Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the ICA, and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC. Additionally, the Double E Pipeline, which provides interstate natural gas transmission service from southeastern New Mexico to the Waha hub in Texas, is subject to FERC jurisdiction under the NGA with respect to post-construction remediation activities, operations, and rates and terms and conditions of service. Pursuant to the NGA, Double E Pipeline's existing interstate natural gas transportation rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate changes and changes to terms and conditions of service proposed by a regulated natural gas interstate pipeline may be protested and such changes can be delayed and may ultimately be rejected by FERC. FERC may also initiate reviews of an interstate pipeline's rates. We cannot guarantee that any new or existing tariff rate for service on our FERC-regulated pipelines would not be rejected or modified by the FERC or subjected to refunds. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations. We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase. As a result, our costs could exceed our revenues. In 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline, which occurred on November 18, 2021 and with total maximum daily transportation quantities that increases from 585,000 Dth/d during the first year of the agreement to 1,000,000 Dth/d in the fourth year, which equates to approximately 67% of its capacity of 1,500,000 Dth/d; these contracts are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our "negotiated or discount rate" contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed "recourse rates" should ever be reduced below applicable discounted rates, we would only be allowed by FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by our assets. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are not generally subject to adjustment for increased costs, which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets. We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC's regulations thereunder, and also must comply with the other applicable provisions of the NGA and NGPA and FERC's rules, regulations, and orders concerning the Double E Pipeline's interstate natural gas pipeline business, including those that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential. Violations of the NGA or NGPA, or the rules, regulations, and orders issued by FERC thereunder could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to approximately $1.5 million per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to approximately $1.5 million per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1.5 million per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA. The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC. We are subject to state and local regulation regarding the construction and operation of our gathering, treating, transporting and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat and process. Many states have adopted complaint-based regulation of gathering, treating, transporting and processing activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal regulations do not directly apply to our business but may nonetheless affect the availability of natural gas and crude oil for gathering, treating, transporting and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues.

Along with our own data and information that we collect and retain in the normal course of our business, we and our business partners collect and retain significant volumes of certain other types of data, some of which are subject to data protection laws. The regulatory environment surrounding the collection, use, transfer and protection of such data, both domestically and internationally, is becoming increasingly complex, constantly evolving, and is subject to frequent significant change. New data protection laws at the federal, state, international, national, provincial and local levels, including recent Colorado, Connecticut, Virginia and Utah legislation, the GDPR and the CCPA, pose increasingly complex compliance challenges and potentially elevate our costs. Complying with these jurisdictional requirements could increase the costs and complexity of compliance procedures, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through business partners. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, imposes specific obligations on businesses that collect personal data from California residents and provides California residents specific rights in relation to their personal data that we or our business partners collect and use. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could necessitate we change our business practices, and carries the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows. As noted below, we are also subject to the possibility of information security breaches, which themselves may result in material financial and reputational exposure under such data protection laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

The DOT, through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream Services LLC system is located. While the majority of our pipelines have historically met the DOT definition of gathering lines and were thus exempt from PHMSA's integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to: - perform ongoing assessments of pipeline integrity;- identify and characterize applicable threats to pipeline segments that could impact a high consequence area;- maintain processes for data collection, integration and analysis;- repair and remediate pipelines as necessary;- adopt and maintain procedures, standards and training programs for control room operations; and - implement preventive and mitigating actions. For additional information on PHMSA regulations relating to pipeline safety, see "-A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase."

Our gathering, treating, transportation and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including: - the level of existing and new competition to provide gathering and/or processing services in our areas of operation;- the macroeconomic factors affecting gathering, treating, transporting and processing economics for our current and potential customers;- the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;- the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and - the effects of federal, state or local regulations on the contracting practices of our customers. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline.

If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our results of operations will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our results of operations and financial condition.

Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Colorado and Texas, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating, transporting and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their locations and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in locations with significant elevation changes, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, wildfires, droughts and floods, changes in weather patterns, extreme temperatures and other climatic events. While we cannot predict with any certainty at this time whether we will be affected by these possibilities, severe weather associated with climate change could result in disruptions or delays to our operations, damage to our assets and facilities and increased operating costs, any of which could materially adversely affect our business and results of operations.

To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under the Amended and Restated ABL Facility or the Permian Transmission Credit Facilities. We plan to use cash from operations, incur borrowings and/or sell additional shares of capital stock or other securities to fund our future expansion capital expenditures. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Stock, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control, including political uncertainty in the U.S. (including the ongoing debates related to the U.S. federal government budget), volatility and disruption in global capital and credit markets (including those resulting from geopolitical events, such as the Russian invasion of Ukraine or the continued conflict in the Middle East), uncertainty regarding increases or decreases in interest rates resulting from changes in the federal funds rate range targeted by the Federal Reserve, pandemics, epidemics and other outbreaks, such as COVID-19, or other adverse developments that affect financial institutions. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. We have not made a dividend on our common stock or Series A Preferred Stock, or prior to the Corporate Reorganization, the common units or Series A Preferred Units, since we announced suspension of those distributions on May 3, 2020, and these suspensions of dividends may further reduce demand for our common stock or Series A Preferred Stock. Because our Series A Preferred Stock ranks senior to our common stock with respect to distribution rights, any accrued amounts on our Series A Preferred Stock must first be paid prior to our resumption of dividends to holders of our common stock. As of December 31, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.4 million. Further, absent a material change to our business, we do not expect to pay dividends on the common stock in the foreseeable future. Additionally, our debt agreements restrict our ability to pay cash dividends on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay dividends to our common equity holders.