WMB/Filings/10-K Diff

WMB 10-K diff: FY 2023-12-31 → FY 2025-12-31

Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).

Item 1A · Risk Factors

+224 paragraphs −161 paragraphs ~161 changed

FY 2023-12-31 (earlier)

Item 1A. Risk Factors FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995The reports, filings, and other public announcements of Williams may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding: • Levels of dividends to Williams stockholders; • Future credit ratings of Williams and its affiliates;• Amounts and nature of future capital expenditures;• Expansion and growth of our business and operations;• Expected in-service dates for capital projects; • Financial condition and liquidity; • Business strategy; • Cash flow from operations or results of operations;• Seasonality of certain business components; • Natural gas, natural gas liquids, and crude oil prices, supply, and demand;• Demand for our services. Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:• Availability of supplies, market demand, and volatility of prices; • Development and rate of adoption of alternative energy sources;• The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability and the ability of other energy companies with whom we conduct or seek to conduct business, to obtain necessary permits and approvals, and our ability to achieve favorable rate proceeding outcomes; • Our exposure to the credit risk of our customers and counterparties; 27 • Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities and consummate asset sales on acceptable terms; • Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities; • The strength and financial resources of our competitors and the effects of competition; • The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate; • Whether we will be able to effectively execute our financing plan; • Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;• The physical and financial risks associated with climate change; • The impacts of operational and developmental hazards and unforeseen interruptions; • The risks resulting from outbreaks or other public health crises;• Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;• Acts of terrorism, cybersecurity incidents, and related disruptions;• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; • Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction- related inputs, including skilled labor; • Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);• Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital; • The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;• Changes in the current geopolitical situation, including the Russian invasion of Ukraine and conflicts in the Middle East including between Israel and Hamas and conflicts involving Iran and its proxy forces;• Changes in U.S. governmental administration and policies;• Whether we are able to pay current and expected levels of dividends; • Additional risks described in our filings with the SEC. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to, and do not intend to, update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise. 28 Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section. RISK FACTORS You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows, and, in some cases, our reputation. The occurrence of any of such risks could also adversely affect the value of an investment in our securities. Risks Related to Our Business The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve. Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production predominantly by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including permitting and environmental regulations, or the lack of available capital have, and may continue to, adversely affect the development and production of existing or additional natural gas reserves and the installation of gathering, storage, and pipeline transportation facilities. The import and export of natural gas supplies may also be affected by such conditions. Low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation, and processing facilities. Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business. Governmentally imposed constraints, such as prohibitions on natural gas hookups in newly constructed buildings and the recently announced permit freeze for new LNG export projects, could also artificially limit new demand for natural gas. A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows. Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow our businesses. Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has had and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.29The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including: • Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities; • Geopolitical turmoil in the Middle East, Eastern Europe, and other producing regions; • The activities of OPEC and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities, including Russia;• The level of consumer demand; • The price and availability of other types of fuels or feedstocks; • The availability of pipeline capacity; • Supply disruptions, including plant outages and transportation disruptions; • The price and quantity of foreign imports and domestic exports of natural gas and oil;• Domestic and foreign governmental regulations and taxes;• The credit of participants in the markets where products are bought and sold.We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk. We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, are required to make prepayments or provide security to satisfy credit concerns, or are dependent upon us, in some cases without a readily available alternative, to provide necessary services. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment, certain of our customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with such customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code or, if we so agree, may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection, or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows, and financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows. We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups. We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups, and other advocates. In some instances, we encounter opposition that disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our 30 assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property, or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations. We may not be able to grow or effectively manage our growth. As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates or assets may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate or assets, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, or fractionation or storage facilities as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns, including due to inflation, could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that: • Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes that are materially different than anticipated; • We could be required to contribute additional capital to support acquired businesses or assets, and we may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate; • Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain our current business standards, controls, and procedures; • Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms. If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows. Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results. We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that we operate could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities, or other factors. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities than we can. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, and cash flows. 31 We do not own 100 percent of the equity interests of certain subsidiaries, including the Nonconsolidated Entities, which may limit our ability to operate and control these subsidiaries. Certain operations, including the Nonconsolidated Entities, are conducted through arrangements that may limit our ability to operate and control these operations. The operations of our current non-wholly-owned subsidiaries, including the Nonconsolidated Entities, are conducted in accordance with their organizational documents. We anticipate that we will enter into more such arrangements, including through new joint venture structures or new Nonconsolidated Entities. We may have limited operational flexibility in such current and future arrangements, and we may not be able to control the timing or amount of cash distributions received. In certain cases: • We cannot control the amount of cash reserves determined to be necessary to operate the business, which reduces cash available for distributions; • We cannot control the amount of capital expenditures that we are required to fund and we are dependent on third parties to fund their required share of capital expenditures; • We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; • We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest; • We have limited ability to influence or control certain day to day activities affecting the operations; • We may have additional obligations, such as required capital contributions, that are important to the success of the operations. In addition, conflicts of interest may arise between us, on the one hand, and other interest owners, on the other hand. If such conflicts of interest arise, we may not have the ability to control the outcome with respect to the matter in question. Disputes between us and other interest owners may also result in delays, litigation, or operational impasses. The risks described above or the failure to continue such arrangements could adversely affect our ability to conduct the operations that are the subject of such arrangements which could, in turn, negatively affect our business, growth strategy, financial condition, and results of operations. We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow. We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including: • The level of existing and new competition in our businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy; • Natural gas and NGL prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems; • General economic, financial markets, and industry conditions; 32 • The effects of regulation on us, our customers, and our contracting practices; • Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market. Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts. Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although other services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Some of our businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers. Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operations, and cash flows. Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business. Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these arrangements could be disrupted. Similarly, the expiration of agreements associated with such arrangements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on others as service providers could have a material adverse effect on our business, financial condition, results of operations, and cash flows. An impairment of our assets, including property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings. GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our property, plant, and equipment, intangible assets, and/or equity-method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings. Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks. Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social and governance (“ESG”) practices. Investor advocacy groups, institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased focus and activism related to ESG (as proponents or opponents) and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for33ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition, and/or stock price of such a company could be materially and adversely affected. We face pressures from our stockholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint, and promote sustainability. Our stockholders may require us to implement ESG procedures or standards in order to continue engaging with us, to remain invested in us or before they may make further investments in us. Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. We adopted certain practices as highlighted in our 2022 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship. It is possible, however, that our stockholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet our stockholders’ expectations, our business, ability to access capital, and/or our stock price could be harmed. Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environments, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business. The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition. We may be subject to physical and financial risks associated with climate change. The threat of global climate change may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. To the extent financial markets view climate change and greenhouse gas (“GHG”) emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services. Our business could also be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change. Our operations are subject to operational hazards and unforeseen interruptions. There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling, including:• Aging infrastructure and mechanical problems; • Damages to pipelines and pipeline blockages or other pipeline interruptions; • Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;• Collapse or failure of storage caverns; 34• Operator error; • Damage caused by third-party activity, such as operation of construction equipment; • Pollution and other environmental risks; • Fires, explosions, craterings, and blowouts; • Security risks, including cybersecurity;• Operating in a marine environment. Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena. Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or the occurrence of a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Our business could be negatively impacted by acts of terrorism and related disruptions. Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. Uncertainty surrounding the Russian invasion of Ukraine, conflicts in the Middle East including between Israel and Hamas and conflicts involving Iran and its proxy forces, or other sustained military campaigns, may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows. A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation. We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. Our Board of Directors has oversight responsibility with regard to assessment of the major risks inherent in our business, including cybersecurity risks, and reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower, and capital in our information technology infrastructure. However, the age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, 35 “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process, and report financial information. Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, which may increase as a result of the Russian invasion of Ukraine or other geopolitical tensions and conflicts, could result in damage to or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows. If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected. We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store, or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnection or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated, or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Our operating results for certain components of our business might fluctuate on a seasonal basis. Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns. We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations. We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our facilities and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Our business could be negatively impacted as a result of stockholder activism. In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including ours. We were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs. If stockholder activists were to again take or threaten to take actions against the Company or seek to involve themselves in the governance, strategic direction, or operations of the Company, we could incur significant costs as well as the distraction of management, which could have an adverse effect on our business or financial results. In addition, actions of activist stockholders may cause significant 36 fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business. Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control. We have defined benefit pension plans and other postretirement benefit plans. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates, and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations. Risks Related to Financing Our Business A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing business. Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by the downgrading of our credit ratings. Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, we have been assigned an investment-grade credit rating by the credit ratings agencies. Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations. Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. Geopolitical tensions and conflicts including those in the Middle East between Israel and Hamas and Iran or its proxy forces, as well as the ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to these conflicts have had, and may continue to have, adverse impacts on global financial markets. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above. Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility. Our total outstanding long-term debt (including current portion and commercial paper) as of December 31, 2023, was $26.4 billion. The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our, and our material subsidiaries’, ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply. 37 Our debt service obligations and the covenants described above could have important consequences. For example, they could: • Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness; • Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes; • Diminish our ability to withstand a continued or future downturn in our business or the economy generally; • Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes; • Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all. Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 12 – Debt and Banking Arrangements. Changes to interest rates or increases in interest rates could adversely impact our access to credit, share price, our ability to issue securities or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels. Interest rates have risen in recent years and may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our dividends and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels. Our hedging activities might not be effective and could increase the volatility of our results. In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default. The difference in accounting treatment for the underlying position and the financial instrument 38 used to hedge the value of the contract can cause volatility in our reported net income while the positions are open due to mark-to-market accounting. Our and our customers’ access to capital could be affected by financial institutions’ policies concerning fossil- fuel related businesses . Public concern regarding the potential effects of climate change have directed increased attention towards the funding sources of fossil-fuel energy companies. As a result, certain financial institutions, funds, and other sources of capital have restricted or eliminated their investment in certain market segments of fossil-fuel related energy. Ultimately, limiting fossil-fuel related companies’ access to capital could make it more difficult for our customers to secure funding for exploration and production activities or for us to secure funding for growth projects. Such a lack of capital could also both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.Risks Related to RegulationsThe operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers. Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations. Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance. In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner that differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to us, our customers, or our business activities. The current U.S. governmental administration and its policies, which often oppose the development or expansion of fossil fuel energy, have increased the likelihood of such legal and regulatory developments. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process, and treat could decline, our compliance costs could increase, and our results of operations could be adversely affected. The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines and storage assets, including a reasonable rate of return. In addition to regulation by other federal, state, and local regulatory authorities, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:• Transportation and sale for resale of natural gas in interstate commerce;39• Rates, operating terms, types of services, and conditions of service; • Certification and construction of new interstate pipelines and storage facilities; • Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities; • Accounts and records; • Depreciation and amortization policies; • Relationships with affiliated companies that are involved in marketing functions of the natural gas business; • Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business. Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations. Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits. Joint and several strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses. In addition, climate change regulations and the costs that may be associated with such regulations and with the regulation of emissions of GHGs have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emission controls on our facilities, or administer and manage any GHG emissions program. We believe it is possible that future governmental legislation and/or regulation may require us either to limit GHG emissions associated with our operations or to purchase allowances for such emissions. We could also be subjected to a carbon tax assessed on the basis of carbon dioxide emissions or otherwise. However, we cannot predict precisely what form these future regulations might take, the stringency of 40 any such regulations or when they might become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions or to purchase allowances for such emissions. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit and reduce GHG emissions from our facilities. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition.General Risk FactorsWe do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims. In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt. Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations. Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, the challenges of attracting new, qualified workers to the midstream energy industry, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully attract and retain an appropriately qualified workforce, including members of senior management, results of operations could be negatively impacted. Holders of our common stock may not receive dividends in the amount expected or any dividends. We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including: • The amount of cash that our subsidiaries distribute to us; • The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow; • The restrictions contained in our indentures and credit facility and our debt service requirements;• The cost of acquisitions, if any.A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price. 41

FY 2025-12-31 (later)

Item 1A. Risk Factors FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995The reports, filings, and other public announcements of Williams, Transco, and NWP may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. Williams, Transco, and NWP make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995, as applicable. All statements, other than statements of historical facts, included in this report that address activities, events, or developments that Williams, Transco, and NWP expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding: • Levels of dividends to Williams’ stockholders; • Future credit ratings of Transco, NWP, and Williams and its affiliates;• Amounts and nature of future capital expenditures;• Expansion and growth of business and operations;• Expected in-service dates for capital projects; • Financial condition and liquidity; • Business strategy; • Cash flow from operations or results of operations;• Rate case filings;• Seasonality of certain business components; • Natural gas, natural gas liquids, and crude oil prices, supply, and demand;• Demand for services. Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond Williams’, Transco’s, and NWP’s ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:• Availability of supplies, market demand, and volatility of prices; • Development and rate of adoption of alternative energy sources;• The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as the ability and the ability of other energy companies with whom Williams, Transco, and NWP conduct or seek to conduct business, to obtain necessary permits and approvals, and the ability to achieve favorable rate proceeding outcomes; 28 • Exposure to the credit risk of customers and counterparties; • Williams’ ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand facilities and consummate asset sales on acceptable terms; • The ability to successfully identify, evaluate, and timely execute on capital projects and investment opportunities; • The strength and financial resources of competitors and the effects of competition; • The amount of cash distributions from and capital requirements of Williams’ investments and joint ventures in which Williams participates; • The ability of Williams to effectively execute on its financing plan; • Increasing scrutiny and changing expectations from stakeholders with respect to environmental, social, and governance practices;• The physical and financial risks associated with climate change; • The impacts of operational and developmental hazards and unforeseen interruptions; • The risks resulting from outbreaks or other public health crises;• Risks associated with weather and natural phenomena, including climate conditions and physical damage to facilities;• Acts of terrorism, cybersecurity incidents, and related disruptions;• Williams’ costs and funding obligations for defined benefit pension plans and other postretirement benefit plans, and Transco’s and NWP’s allocations regarding the same; • Changes in maintenance and construction costs, as well as the ability to obtain sufficient construction- related inputs, including skilled labor; • Inflation, interest rates, tariffs on foreign-made materials and goods (including steel and steel pipes) necessary to conduct business, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);• Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital; • The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;• Changes in the current geopolitical situation;• Changes in U.S. governmental administration and policies;• Whether Williams is able to pay current and expected levels of dividends; • Additional risks described in Williams’, Transco’s, and NWP’s SEC filings. Given the uncertainties and risk factors that could cause Williams’, Transco’s, and NWP’s actual results to differ materially from those contained in any forward-looking statement, Williams, Transco, and NWP caution investors not to unduly rely on these forward-looking statements. Williams, Transco, and NWP disclaim any obligations to, and do not intend to, update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. In addition to causing actual results to differ, the factors listed above and referred to below may cause Williams’, Transco’s, and NWP’s intentions to change from those statements of intention set forth in this report.29Such changes in intentions may also cause results to differ. Williams, Transco, and NWP may change intentions, at any time and without notice, based upon changes in such factors, assumptions, or otherwise. Because forward-looking statements involve risks and uncertainties, Williams, Transco, and NWP caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section. Summary of Risk Factors You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect Williams’, Transco’s, and NWP’s businesses, prospects, financial condition, results of operations, cash flows, and, in some cases, reputation. The occurrence of any of such risks could also adversely affect the value of an investment in securities. These factors are summarized below and described in more detail following the summary. Risks Related to Business • The business, operating results, and financial condition of Williams’, Transco’s, and NWP’s natural gas transportation and midstream businesses are dependent on the continued availability of natural gas supplies in the supply basins and demand for those supplies in the markets that they serve. • Prices for natural gas, NGLs, oil, LNG, and other commodities are volatile, and this volatility has and could continue to adversely affect Williams’ financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow its business. • Significant prolonged changes in natural gas prices could affect supply and demand for Transco and NWP and cause a reduction in or termination of their long-term transportation and storage contracts or throughput on their systems. • Williams, Transco, and NWP are exposed to the credit risk of customers and counterparties, and credit risk management will not be able to completely eliminate such risk. • Williams, Transco, and NWP may not be able to grow or effectively manage growth, including the pursuit and operational implementation of power innovation projects. • The energy industry is highly competitive, and increased competitive pressure could adversely affect Williams’, Transco’s, and NWP’s businesses and operating results. • Williams does not own 100 percent of the equity interests of certain subsidiaries, including the nonconsolidated entities, which may limit its ability to operate and control these subsidiaries. Certain operations, including the nonconsolidated entities, are conducted through arrangements that may limit Williams’ ability to operate and control these operations. • Williams, Transco, and NWP may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, as applicable, which could affect Williams’, Transco’s, and NWP’s financial condition and ability to grow, as well as the amount of cash available to Williams to pay dividends. • Certain of Williams’, Transco’s, and NWP’s natural gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts. • Some of Williams’, Transco’s, and NWP’s businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers. • Transco and NWP depend on certain key customers for a significant portion of their revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in Transco’s and NWP’s respective businesses. • Failure of service providers or disruptions to outsourcing relationships might negatively impact Williams’, Transco’s, and NWP’s ability to conduct business. 30 • An impairment of Williams’ assets, including property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce Williams’ earnings. • Williams, Transco, and NWP may face opposition to the operation and expansion of pipelines and facilities from various individuals and groups or face increased scrutiny from various stakeholders with respect to environmental, social and governance practices. • Williams, Transco, and NWP may be subject to physical and financial risks associated with climate change. • Williams’, Transco’s, and NWP’s operations are subject to operational risks and hazards that might result in unforeseen interruptions. • Williams’, Transco’s, and NWP’s assets and operations, as well as their customers’ assets and operations, can be adversely affected by weather and other natural phenomena. • Williams’, Transco’s, and NWP’s businesses could be negatively impacted by acts of terrorism and related disruptions. • A breach of information technology infrastructure, including a breach caused by a cybersecurity attack on Williams, Transco, or NWP, or the third parties with whom they are interconnected, may interfere with the safe operation of assets, result in the disclosure of personal or proprietary information, and cause reputational harm. • If third-party pipelines and other facilities interconnected to Williams’, Transco’s, and NWP’s pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, as applicable, Williams’, Transco’s, and NWP’s revenues could be adversely affected. • Williams’ operating results for certain components of its business might fluctuate on a seasonal basis. • Williams, Transco, and NWP do not own all of the land on which their pipelines and facilities are located, which could disrupt operations. • Williams’ business could be negatively impacted as a result of stockholder activism. • Williams’ costs and funding obligations for defined benefit pension plans and other postretirement benefit plans, and Transco’s and NWP’s allocations regarding the same, are affected by factors beyond Williams’ control. Risks Related to Financing • A downgrade of Williams’, Transco’s, and NWP’s credit ratings, which are determined outside of their control by independent third parties, could impact liquidity, access to capital, and costs of doing business, and the ability of Transco and NWP to obtain credit in the future could be affected by Williams’ credit ratings. • Difficult conditions in the global financial markets and the economy in general could negatively affect Williams’, Transco’s, and NWP’s businesses and results of operations. • Restrictions in Williams’, Transco’s, and NWP’s debt agreements and the amount of their indebtedness may affect their future financial and operating flexibility. • Changes to interest rates or increases in interest rates could adversely impact Williams’, Transco’s, and NWP’s access to credit, share price and ability to issue securities or incur debt for acquisitions or other purposes, as applicable, and Williams’ ability to make cash dividends at intended levels. • Williams’ hedging activities might not be effective and could increase the volatility of Williams’ results. • Access to capital could be affected by financial institutions’ policies concerning fossil-fuel related businesses. • Williams can exercise substantial control over Transco’s and NWP’s distribution policies, businesses and operations and may do so in a manner that is adverse to Transco’s and NWP’s interests. 31 Risks Related to Regulation s • The operation of Williams’, Transco’s, and NWP’s businesses might be adversely affected by regulatory proceedings, including FERC proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to Williams’, Transco’s, and NWP’s businesses or customers. • Williams’, Transco’s, and NWP’s operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose them to significant costs, liabilities, and expenditures that could exceed expectations. General Risk Factors • Williams, Transco, and NWP do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of insurers to satisfy claims. • Failure to attract and retain an appropriately qualified workforce could negatively impact Williams’, Transco’s, and NWP’s results of operations. • Holders of Williams’ common stock may not receive dividends in the amount expected or any dividends. Risk Factors Risks Related to Business The business, operating results, and financial condition of Williams’, Transco’s, and NWP’s natural gas transportation and midstream businesses are dependent on the continued availability of natural gas supplies in the supply basins and demand for those supplies in the markets that they serve. The ability of Williams, Transco, and NWP to maintain and expand their natural gas transportation and midstream businesses depends on the level of drilling and production, predominantly by third parties, in the supply basins near Williams’, Transco’s, and NWP’s pipelines and gathering systems. Production from existing wells and natural gas supply basins with access to Williams’, Transco’s, and NWP’s pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Williams, Transco, and NWP do not obtain independent evaluations of natural gas reserves, and thus, do not have independent estimates of total reserves dedicated to, or the anticipated life of reserves connected to, Williams’, Transco’s, and NWP’s systems and processing facilities. In addition, low prices for natural gas, regulatory limitations, including permitting and environmental regulations, or the lack of available capital have, and may continue to, adversely affect the development and production of existing or additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities, and the import and export of natural gas suppliers. Localized low natural gas prices in one or more of the existing supply basins connected to Williams, Transco, or NWP, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas available. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for customers. A failure to obtain access to sufficient natural gas supplies will adversely impact Williams’, Transco’s, and NWP’s ability to maximize the capacities of their gathering, transportation, and processing facilities, as applicable. Demand for Williams’, Transco’s, and NWP’s services is dependent on the demand for gas in the markets served. Demand for natural gas can be affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, technological advances in fuel economy, energy generation, and renewable sources of energy, and governmentally imposed constraints, such as prohibitions on natural gas hookups in newly constructed buildings, all of which are matters beyond Williams’, Transco’s, and NWP’s control. A failure to obtain access to sufficient natural gas supplies or a reduction in demand for services in the markets served by Williams, Transco, and NWP could result in impairments of Williams’ assets and have a material adverse effect on Williams’, Transco’s, and NWP’s businesses, financial condition, results of operations, and cash flows. 32 Prices for natural gas, NGLs, oil, LNG, and other commodities are volatile, and this volatility has and could continue to adversely affect Williams’ financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow its business. Williams’ revenues, operating results, future rate of growth, and the value of certain components of its business depend primarily upon the prices of natural gas, NGLs, oil, LNG, or other commodities, and the differences between prices of these commodities, and could be materially adversely affected by an extended period of low commodity prices or a decline in commodity prices. Price volatility has and could continue to impact both the amount Williams receives for products and services and the volume of products and services sold. Prices affect the amount of cash flow available for capital expenditures and Williams’ ability to borrow money or raise additional capital. Price volatility has had, and could continue to have, an adverse effect on Williams’ business, results of operations, financial condition, and cash flows. The markets for natural gas, NGLs, oil, LNG, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond Williams’ control, including: • Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, LNG, and related commodities; • Geopolitical turmoil in producing regions; • The activities of OPEC and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas, or other commodity production capabilities, including Russia;• The level of consumer demand; • The price and availability of other types of fuels or feedstocks; • The availability of pipeline capacity; • Supply disruptions, including plant outages and transportation disruptions; • The price and quantity of foreign imports and domestic exports of natural gas and oil;• Domestic and foreign governmental regulations and taxes; and• The credit of participants in the markets where products are bought and sold.Significant prolonged changes in natural gas prices could affect supply and demand for Transco and NWP and cause a reduction in or termination of their long-term transportation and storage contracts or throughput on their systems. Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in Transco’s and NWP’s long-term transportation and storage contracts or throughput on their systems. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas, resulting in reduced contracts or throughput on their systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on Transco’s and NWP’s businesses, financial condition, results of operations, and cash flows. Williams, Transco, and NWP are exposed to the credit risk of customers and counterparties, and credit risk management will not be able to completely eliminate such risk. Williams, Transco, and NWP are subject to the risk of loss resulting from nonpayment and/or nonperformance by customers and counterparties in the ordinary course of business. Generally, Williams’, Transco’s, and NWP’s customers are rated investment grade, are otherwise considered creditworthy, are required to make prepayments or provide security to satisfy credit concerns, or are dependent upon Williams, Transco or NWP, in some cases without a readily available alternative, to provide necessary services. However, Williams’, Transco’s, and NWP’s credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Williams’, Transco’s, and NWP’s customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to33energy producing activities. In a low commodity price environment, certain customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate contracts. To the extent one or more of Williams’, Transco’s, or NWP’s key customers commences bankruptcy proceedings, the contracts with such customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection, or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for services less than contractually required, which could have a material adverse effect on Williams’, Transco’s, and NWP’s businesses, results of operations, cash flows, and financial condition. If Williams, Transco, and NWP fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause Williams, Transco, or NWP to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect Williams’, Transco’s, or NWP’s operating results for the period in which they occur, and, if significant, could have a material adverse effect on Williams’, Transco’s, or NWP’s businesses, financial condition, results of operations, and cash flows. Williams, Transco, and NWP may not be able to grow or effectively manage growth, including the pursuit and operational implementation of power innovation projects. As part of Williams’ growth strategy, Williams considers acquisition opportunities. Suitable acquisition candidates or assets may not be available on terms and conditions Williams finds acceptable or, where multiple parties are trying to acquire an acquisition candidate or assets, Williams may not be chosen as the acquirer. If Williams is able to acquire a targeted business, Williams may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Additionally, as part of Williams’, Transco’s, and NWP’s growth strategy, Williams, Transco, and NWP engage in significant capital projects and have both a project lifecycle process and an investment evaluation process. These are the processes used to identify, evaluate, and execute on capital projects, and the investment evaluation process is used by Williams’ to identify, evaluate, and execute on acquisitions. Williams, Transco, and NWP may not always have sufficient and accurate information to identify and value potential opportunities and risks or the investment evaluation process may be incomplete or flawed. Growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, or fractionation or storage facilities as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns, including due to inflation or the imposition of tariffs on foreign-made materials and goods (including steel and steel pipes) necessary to conduct business, could cause total project costs to exceed budgeted costs. Additional risks associated with growing the business include, among others, that: • Changing circumstances and deviations in variables could negatively impact the investment analysis, including projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes that are materially different than anticipated; • Williams, Transco, or NWP could be required to contribute additional capital to support acquired businesses or assets, and Williams, Transco, or NWP may assume liabilities that were not disclosed, exceed estimates and for which contractual protections are either unavailable or prove inadequate; • Acquisitions could disrupt ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain current business standards, controls, and procedures; • Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and Williams, Transco, or NWP may not be able to access credit or capital markets or obtain acceptable terms. If realized, any of these risks could have an adverse impact on Williams’, Transco’s, and NWP’s financial condition, results of operations, including the possible impairment of assets, or cash flows. 34 Further, Williams has invested in several power innovation projects and continues to evaluate power innovation projects related to data center growth. Additional risks associated with identifying, evaluating, and executing on power innovation projects may include accurately predicting future power needs of data centers due to rapidly changing technology and market dynamics, which could result in underutilized or stranded assets; managing the potential power demand; obtaining or constructing power generation sources, including sourcing turbines and batteries and maintaining other transmission capabilities to meet potential load growth from any data center customer; financing the capital investment needed to build and maintain the necessary infrastructure to support data center development; managing community opposition; managing the possible environmental impact of power innovation projects, and evaluating and complying with evolving regulations related to data center development. Risks associated with construction are similar to those described above for other capital projects, including obtaining long-lead specialized equipment and materials, such that projects are completed, on time or at all, and the risk that construction cost overruns, including due to inflation or the imposition of tariffs on foreign-made materials and goods necessary to conduct business, could cause total project costs to exceed budgeted costs. Williams’ behind the meter power generation projects require the constant, reliable production of electricity, which if not met, may result in contractual penalties and reputational damage, among other consequences. If realized, any of these risks could have an adverse impact on Williams’ financial condition, results of operations, including the possible impairment of assets, or cash flows. The energy industry is highly competitive, and increased competitive pressure could adversely affect Williams’, Transco’s, and NWP’s businesses and operating results. Williams has numerous competitors in all aspects of its businesses, and additional competitors may enter its markets. Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that Williams operates could offer transportation services that are more desirable to shippers than those Williams provides because of price, location, facilities, or other factors. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources, which could affect Williams’ ability to make strategic investments or acquisitions. Competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities. Further, natural gas also competes with other forms of energy available to customers, including electricity, coal, fuel oils, and other alternative energy sources. Failure to successfully compete against current and future competitors could have a material adverse effect on Williams’ business, results of operations, financial condition, and cash flows. Similarly, Transco and NWP compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. The principal elements of competition among interstate natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. Although most of Transco’s and NWP’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. Similarly, a highly liquid competitive commodity market in natural gas, and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, Transco and NWP could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If Transco and NWP are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, they or their remaining customers, may have to bear the costs associated with the turned back capacity. Moreover, Williams and its other affiliates may not be limited in their ability to compete with Transco and NWP. Additionally, some of Transco’s and NWP’s competitors may have greater financial resources and access to greater supplies of natural gas than they do. Some of these competitors may expand or construct transportation and storage systems that would serve the same markets as Transco and NWP or create additional competition for natural gas supplies or the services provided to customers. Any new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, rates, or other factors. Transco and NWP are aware of proposals by competitors to expand pipeline capacity in certain markets Transco and NWP also serve. Transco and NWP may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on Transco’s and NWP’s businesses, financial condition, results of operations, and cash flows. 35 Williams does not own 100 percent of the equity interests of certain subsidiaries, including the nonconsolidated entities, which may limit its ability to operate and control these subsidiaries. Certain operations, including the nonconsolidated entities, are conducted through arrangements that may limit Williams’ ability to operate and control these operations. The operations of Williams’ current non-wholly owned subsidiaries are conducted in accordance with their organizational documents. Williams anticipates that it will enter into more such arrangements, including through new joint venture structures. Williams may have limited operational flexibility in such current and future arrangements and may not be able to control the timing or amount of cash distributions received. In certain cases: • Williams cannot control the amount of cash reserves determined to be necessary to operate the business, which reduces cash available for distributions; • Williams cannot control the amount of capital expenditures that it is required to fund, and Williams is dependent on third parties to fund their required share of capital expenditures; • Williams may be subject to restrictions or limitations on its ability to sell or transfer its interests in the jointly owned assets; • Williams may be forced to offer rights of participation to other joint venture participants in the area of mutual interest; • Williams has limited ability to influence or control certain day to day activities affecting the operations; and • Williams may have additional obligations, such as required capital contributions that are important to the success of the operations. In addition, conflicts of interest may arise between Williams, on the one hand, and other interest owners, on the other hand. If such conflicts of interest arise, Williams may not have the ability to control the outcome with respect to the matter in question. Disputes between Williams and other interest owners may also result in delays, litigation, or operational impasses. The risks described above or the failure to continue such arrangements could adversely affect Williams’ ability to conduct the operations that are the subject of such arrangements which could, in turn, negatively affect Williams’ business, growth strategy, financial condition, and results of operations. Williams, Transco, and NWP may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, as applicable, which could affect Williams’, Transco’s, and NWP’s financial condition and ability to grow, as well as the amount of cash available to Williams to pay dividends. Williams, Transco, and NWP rely on a limited number of customers and producers for a significant portion of revenues and supply of natural gas and NGLs, as applicable. Although many of Williams’, Transco’s, and NWP’s customers and suppliers are subject to long-term contracts, if Williams, Transco, and NWP are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to it by current producers, in each case on favorable terms, if at all, Williams’, Transco’s, and NWP’s businesses, financial condition, results of operations, and cash flows, as well as Williams’ growth plans and the amount of cash available to pay dividends could be materially adversely affected. Williams’, Transco’s, and NWP’s ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond their control, including: • The level of existing and new competition in Williams’, Transco’s, and NWP’s businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy; • General economic, financial markets, and industry conditions; • The effects of regulation on Williams, Transco, and NWP, their customers, and their contracting practices; 36 • Williams’, Transco’s, and NWP’s ability to understand their customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The results of these efforts will impact Williams’, Transco’s, and NWP’s reputation and positioning in the market. In addition, Williams’ markets are affected by natural gas and NGL prices, demand, availability, and margins. Higher prices for energy commodities related to Williams’ businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on the pipeline systems. Lower energy commodity prices could negatively impact the ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on the pipeline systems. Certain of Williams’, Transco’s, and NWP’s natural gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts. Williams’, Transco’s, and NWP’s natural gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues collected. Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect Williams’, Transco’s, and NWP’s businesses in many ways, including decreasing tariff rates and revenues or setting future tariff rates to levels such that revenues are inadequate to recover increases in operating costs or to sustain an adequate return on capital investments, decreasing volumes in the pipelines, increasing costs, and otherwise altering the profitability of the pipeline business. Additionally, although other services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Further, the costs of testing, maintaining, or repairing regulated facilities for Williams, Transco, and NWP may exceed Williams’, Transco’s and NWP’s expectations, and the FERC may not allow, or competition in the markets may prevent, recovery of such costs in the rates charged for applicable services at Williams’, Transco’s, and NWP’s regulated pipelines and facilities. Williams, Transco and NWP have experienced and could experience in the future unexpected leaks or ruptures on their regulated natural gas pipeline systems or storage facilities. Either as a preventative measure or in response to a leak or another issue, Williams, Transco and NWP could be required by regulatory authorities to test or undertake modifications to their regulated systems. If the cost of testing, maintaining, or repairing regulated facilities exceeds expectations, and the FERC does not allow recovery, or competition in the markets prevents recovering such costs in the rates charged for Williams’, Transco’s and NWP’s regulated services, such costs could have a material adverse impact on Williams’, Transco’s and NWP’s businesses, financial condition, results of operation, and cash flows. Furthermore, Transco charges its transportation customers a separate fee to access its offshore facilities in the Gulf of America, unlike other interstate pipelines that own facilities offshore. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the applicable facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity can result in producers bypassing Transco’s offshore facilities in favor of alternative transportation facilities. Some of Williams’, Transco’s, and NWP’s businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers. Some of Williams’, Transco’s, and NWP’s businesses may be dependent on a small number of suppliers for the delivery of critical goods or services. If a supplier on which one of the businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If Williams’, Transco’s, and NWP’s businesses are unable to adequately diversify or otherwise mitigate such supplier concentration risks, and such risks were realized, such 37 businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on Williams’, Transco’s, and NWP’s financial condition, results of operations, and cash flows. Transco and NWP depend on certain key customers for a significant portion of their revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in Transco’s and NWP’s respective businesses. Transco and NWP rely on a limited number of customers for a significant portion of their revenues. Although some of these customers are subject to long-term contracts, Transco and NWP may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2025, Transco’s largest customer was Duke Energy Corporation, which accounted for approximately 9 percent of its operating revenue, and NWP’s largest customer was Puget Sound Energy, Inc., which accounted for approximately 31 percent of its operating revenue. The loss of all, or even a portion of, the revenues from contracted volumes supplied by Transco’s and NWP’s key customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts, or otherwise, could have a material adverse effect on their businesses, financial condition, results of operations, and cash flows. For more information regarding Transco’s and NWP’s customer revenues, please read Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk. Failure of service providers or disruptions to outsourcing relationships might negatively impact Williams’, Transco’s, and NWP’s ability to conduct their businesses. Transco and NWP rely on Williams and other third parties for certain services necessary for Transco and NWP to be able to conduct business. Certain of Williams’ accounting and information technology services, which are relied upon by Transco and NWP, are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these arrangements could be disrupted. Similarly, the expiration of agreements associated with such arrangements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Williams’ reliance on others as service providers, and Transco’s and NWP’s reliance on Williams’ reliance on others as service providers, could have a material adverse effect on Williams’, Transco’s, and NWP’s businesses, financial condition, results of operations, and cash flows. An impairment of Williams’ assets, including property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce Williams’ earnings. GAAP requires Williams to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of Williams’ assets including property, plant, and equipment, intangible assets, and/ or equity-method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If Williams determines that an impairment has occurred, Williams would be required to take an immediate noncash charge to earnings. Williams, Transco, and NWP may face opposition to the operation and expansion of pipelines and facilities from various individuals and groups or face increased scrutiny from various stakeholders with respect to environmental, social and governance practices. Williams, Transco, and NWP have experienced, and anticipate continuing to face, opposition to the operation and expansion of pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups, and other advocates. In some instances, Williams, Transco, and NWP encounter opposition that disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage operations, intervention in regulatory or administrative proceedings involving assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property, or the environment or lead to extended interruptions of operations. Any such event that delays or prevents the expansion of Williams’, Transco’s, or NWP’s businesses, that interrupts the revenues generated by operations, or that causes significant expenditures not covered by insurance, could adversely affect Williams’, Transco’s, and NWP’s financial condition and results of operations. 38 Additionally, companies across all industries have faced and may continue to face scrutiny from stakeholders related to their environmental, social and governance (“ESG”) practices. Focus and activism related to ESG (as proponents or opponents) and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition, and/or stock price of such a company could be materially and adversely affected. Williams, Transco, and NWP face pressures from their stakeholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce carbon footprint, and promote sustainability. Williams’ stockholders may require Williams to implement ESG procedures or standards to continue engaging with Williams, to remain invested in Williams, or before they may make further investments in Williams. Additionally, Williams, Transco, and NWP may face reputational challenges in the event their ESG procedures or standards do not meet the standards set by certain constituencies. Williams, Transco, and NWP adopted certain practices as highlighted in Williams’ 2024 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship. It is possible, however, that Williams’, Transco’s, and NWP’s stakeholders might not be satisfied with these sustainability efforts or the speed of their adoption. If Williams, Transco and NWP do not meet stakeholders’ expectations, Williams’, Transco’s, and NWP’s businesses, ability to access capital, and/or Williams’ stock price could be harmed. Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environments, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors’ expectations regarding ESG matters, may also adversely affect demand for Williams’, Transco’s, and NWP’s services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on Williams’, Transco’s, and NWP’s businesses. The occurrence of any of the foregoing could have a material adverse effect on the price of Williams’ stock and Williams’, Transco’s, and NWP’s businesses and financial condition. Williams, Transco, and NWP may be subject to physical and financial risks associated with climate change. The threat of global climate change may create physical and financial risks to Williams’, Transco’s, and NWP’s businesses. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require Williams, Transco, and NWP to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect Williams’, Transco’s, and NWP’s financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of Williams’, Transco’s, and NWP’s operating territory could also have an impact on their revenues. To the extent the frequency of extreme weather events increases, this could increase the cost of providing service. Williams, Transco, and NWP may not be able to pass on the higher costs to customers or recover all costs related to mitigating these physical risks. Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for Williams’, Transco’s, and NWP’s assets in areas subject to severe weather. These climate-related changes could damage physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. To the extent financial markets view climate change and greenhouse gas (“GHG”) emissions as a financial risk, this could negatively impact Williams’, Transco’s, and NWP’s cost of and access to capital. Climate change and GHG regulation could also reduce demand for Williams’, Transco’s, and NWP’s services. The business could also be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change. 39 Williams’, Transco’s, and NWP’s operations are subject to operational risks and hazards that might result in accidents and unforeseen interruptions. There are operational risks and hazards associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling, including:• Aging infrastructure and mechanical problems; • Damages to pipelines and pipeline blockages or other pipeline interruptions; • Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;• Collapse or failure of storage facilities or caverns, as applicable;• Operator error; • Damage caused by third-party activity, such as operation of construction equipment; • Pollution and other environmental risks; • Fires, explosions, craterings, and blowouts; • Security risks, including cybersecurity;• Operating in a marine environment, as applicable. Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of operations, loss of services to customers, reputational damage, and substantial losses to Williams, Transco, and NWP. The location of certain segments of Williams’, Transco’s, and NWP’s facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damage resulting from these risks. An event such as those described above could have a material adverse effect on Williams’, Transco’s, and NWP’s financial condition and results of operations, particularly if the event is not fully covered by insurance. Williams’, Transco’s, and NWP’s assets and operations, as well as their customers’ assets and operations, can be adversely affected by weather and other natural phenomena. Williams’, Transco’s, and NWP’s assets and operations, especially those located offshore, and their customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for Williams, Transco, and NWP to realize the historic rates of return associated with their assets and operations. A significant disruption in Williams’, Transco’s, and NWP’s or their customers’ operations or the occurrence of a significant liability for which Williams, Transco, and NWP are not fully insured could have a material adverse effect on their businesses, financial condition, results of operations, and cash flows. Williams’, Transco’s, and NWP’s businesses could be negatively impacted by acts of terrorism and related disruptions. Given the volatile nature of the commodities Williams, Transco, and NWP transport, process, store, and sell, their assets and the assets of their customers and others in the industry may be targets of terrorist activities. Uncertainty surrounding the Russian invasion of Ukraine, conflicts in the Middle East, or other sustained military campaigns, may affect Williams’, Transco’s, and NWP’s operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism. A terrorist attack could create significant price volatility, disrupt business, limit access to capital markets, or cause significant harm to operations, such as full or partial disruption to Williams’, Transco’s, and NWP’s ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities, as applicable. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on Williams’, Transco’s, and NWP’s businesses, financial condition, results of operations, and cash flows. 40 A breach of information technology infrastructure, including a breach caused by a cybersecurity attack on Williams, Transco, or NWP, or the third parties with whom they are interconnected, may interfere with the safe operation of assets, result in the disclosure of personal or proprietary information, and cause reputational harm. Williams relies on its information technology infrastructure to process, transmit, and store electronic information, including information used to safely operate Williams’, Transco’s, and NWP’s assets. Transco and NWP rely on Williams for their information technology infrastructure. The Williams Board of Directors has oversight responsibility with regard to cybersecurity risks, and reviews management’s efforts to address and mitigate cybersecurity risks, including the establishment and implementation of policies to address cybersecurity threats. Williams has invested, and expects to continue to invest, significant time, manpower, and capital in its information technology infrastructure. However, the age, operating systems, or condition of the current information technology infrastructure and software assets and the ability to maintain and upgrade such assets could affect Williams’, and thus Transco’s and NWP’s, ability to resist cybersecurity threats. While Williams believes that it maintains appropriate information security policies, practices, and protocols, Williams regularly faces cybersecurity and other security threats to its information technology infrastructure, including risks that may be enhanced through the use of artificial intelligence, which could include threats to operational industrial control systems and safety systems that operate its pipelines, plants, and assets. Williams faces unlawful attempts to gain access to its information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. Williams faces the threat of theft and misuse of sensitive data and information, including customer and employee information. Williams also faces attempts to gain access to information related to its assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. Williams is also subject to cybersecurity risks arising from the fact that Williams’, Transco’s, and NWP’s business operations are interconnected with third parties, including third-party pipelines, other facilities and contractors and vendors. In addition, the breach of certain business systems could affect Williams’ ability to correctly record, process, and report financial information. Breaches in Williams’, Transco’s, and NWP’s information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, which may increase as a result of the Russian invasion of Ukraine or other geopolitical tensions and conflicts, could result in damage to or destruction of assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on Williams’, Transco’s, and NWP’s operations, financial condition, results of operations, and cash flows. If third-party pipelines and other facilities interconnected to Williams’, Transco’s, and NWP’s pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, as applicable, Williams’, Transco’s, and NWP’s revenues could be adversely affected. Williams, Transco, and NWP depend upon third-party pipelines and other facilities that provide delivery options to and from their pipelines and storage facilities for the benefit of their customers that is outside Williams’ Transco’s, and NWP’s control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, Williams, Transco, and NWP and their customers would have reduced capacity to transport, store, or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, as applicable, thereby reducing revenues. Any temporary or permanent interruption at any key pipeline interconnection or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on Williams’, Transco’s, or NWP’s pipelines or gathering systems, as applicable, or processed, fractionated, treated, or stored at Williams’, Transco’s, or NWP’s facilities, as applicable, could have a material adverse effect on Williams’, Transco’s, and NWP’s businesses, financial condition, results of operations, and cash flows. Williams’ operating results for certain components of its business might fluctuate on a seasonal basis. Revenues from certain components of Williams’ business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, Williams’ overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could 41 vary significantly from Williams’ expectations depending on the nature and location of its facilities and pipeline systems and the terms of the natural gas transportation arrangements relative to demand created by unusual weather patterns. Williams, Transco, and NWP do not own all of the land on which their pipelines and facilities are located, which could disrupt operations. Williams, Transco, and NWP do not own all of the land on which their pipelines and facilities have been constructed. As such, Williams, Transco, and NWP are subject to the possibility of increased costs to retain necessary land use. In those instances in which Williams, Transco and NWP do not own the land on which their facilities are located, Williams, Transco, and NWP obtain the rights to construct and operate their facilities and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of Williams’ and NWP’s facilities cross Native American lands pursuant to rights-of-way of limited terms. Williams and NWP may not have the right of eminent domain over land owned by Native American tribes. Williams’, Transco’s, and NWP’s loss of any of these rights, through their inability to renew right-of-way contracts or otherwise, could have a material adverse effect on their businesses, financial condition, results of operations, and cash flows. Williams’ business could be negatively impacted as a result of stockholder activism. In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including Williams. Williams was the target of a proxy contest from a stockholder activist, which resulted in Williams incurring significant costs. If stockholder activists were to again take or threaten to take actions against Williams or seek to involve themselves in the governance, strategic direction, or operations of Williams, Williams could incur significant costs as well as the distraction of management, which could have an adverse effect on Williams’ business or financial results. In addition, actions of activist stockholders may cause significant fluctuations in Williams’ stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of Williams’ business. Williams’ costs and funding obligations for defined benefit pension plans and other postretirement benefit plans, and Transco’s and NWP’s allocations regarding the same, are affected by factors beyond Williams’ control. Williams has defined benefit pension plans and other postretirement benefit plans. The timing and amount of the funding requirements under the defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates, and changes in pension laws. Changes to these and other factors can significantly increase Williams’ funding requirements and could have a significant adverse effect on Williams’ financial condition and results of operations. Transco and NWP have no employees; employees of Williams and its affiliates provide services to Transco and NWP. As a result, Transco and NWP are allocated a portion of Williams’ cost for defined benefit pension plans and other postretirement benefit plans. The timing and amount of these allocations depends on factors that Williams controls, and any changes can significantly increase the allocations, which could have a significant adverse effect on Transco’s and NWP’s financial condition and results of operations. Risks Related to Financing A downgrade of Williams’, Transco’s, and NWP’s credit ratings, which are determined outside of their control by independent third parties, could impact their liquidity, access to capital, and costs of doing business, and the ability of Transco and NWP to obtain credit in the future could be affected by Williams’ credit ratings. Downgrades of Williams’, Transco’s, and NWP’s credit ratings increase the cost of borrowing and could require Williams, Transco, and NWP to provide collateral to their counterparties, negatively impacting available liquidity. In addition, Williams’, Transco’s, and NWP’s ability to access capital markets could be limited by the downgrading of their credit ratings. Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. 42 Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, Williams, Transco, and NWP have been assigned an investment-grade credit rating by the credit ratings agencies. In addition, substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends, and distributions paid to it by its subsidiaries. Due to the relationship of Transco and NWP as subsidiaries of Williams, Transco’s and NWP’s ability to obtain credit will be affected by Williams’ credit ratings. Any downgrading of a Williams credit rating could result in a downgrading of a Transco and NWP credit rating, which could adversely affect Transco’s and NWP’s access to capital and limit their ability to obtain financing in the future upon favorable terms, if at all. Difficult conditions in the global financial markets and the economy in general could negatively affect Williams’, Transco’s, and NWP’s businesses and results of operations. Williams’, Transco’s, and NWP’s businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for Williams’, Transco’s, and NWP’s products and services and increased difficulty in collecting amounts owed to them by customers. Geopolitical tensions and conflicts, including those in the Middle East, as well as the ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to these conflicts, have had, and may continue to have, adverse impacts on global financial markets. If financing is not available when needed, or is available only on unfavorable terms, Williams, Transco, and NWP may be unable to implement their business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact Williams, Transco, and NWP in the manner described above. Williams, Transco and NWP are party to a credit agreement with aggregate commitments available of $3.75 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Transco and NWP are each subject to a $500 million borrowing sublimit. The ability of Williams, Transco, and NWP to borrow under that facility could be impaired if one or more of the lenders fails to honor its contractual obligation to lend. For more information regarding financing, please read Note 13 – Debt and Banking Arrangements. Restrictions in Williams’, Transco’s, and NWP’s debt agreements and the amount of their indebtedness may affect their future financial and operating flexibility. Williams’ total outstanding long-term debt (including current portion and commercial paper) as of December 31, 2025, was $29.4 billion, including the long-term debt of Transco and NWP. The total outstanding long-term debt (including current portion) as of December 31, 2025, for Transco and NWP was $5.9 billion and $748 million, respectively. The agreements governing Williams’, Transco’s, and NWP’s indebtedness contain covenants that restrict Williams’, Transco’s, and NWP’s, as applicable, and their respective subsidiaries’, ability to incur certain liens to support indebtedness, and ability to merge or consolidate or sell all or substantially all of its respective assets in certain circumstances. In addition, certain of Williams’, Transco’s, and NWP’s debt agreements contain various covenants that restrict or limit, among other things, the ability to make certain distributions during the continuation of an event of default, and to enter into certain affiliate transactions and certain restrictive agreements. Certain of Williams’, Transco’s, and NWP’s debt agreements also contain, and those Williams, Transco, and NWP enter into in the future may contain, financial covenants, and other limitations with which they will need to comply. Williams’, Transco’s, and NWP’s debt service obligations and the covenants described above could have important consequences. For example, they could: • Make it more difficult for Williams, Transco, and NWP to satisfy their obligations with respect to their indebtedness, which could in turn result in an event of default on such indebtedness; 43 • Impair Williams’, Transco’s, and NWP’s ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or limited liability company purposes, as applicable, or other purposes; • Diminish Williams’, Transco’s, and NWP’s ability to withstand a continued or future downturn in their business or the economy generally; • Require Williams, Transco, and NWP to dedicate a substantial portion of their cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes or limited liability company purposes, as applicable, or other purposes; • Limit Williams’, Transco’s, and NWP’s flexibility in planning for, or reacting to, changes in their business and the industry in which they operate, including limiting their ability to expand or pursue business activities and preventing Williams, Transco, and NWP from engaging in certain transactions that might otherwise be considered beneficial to Williams, Transco, and NWP. Williams’, Transco’s, and NWP’s ability to comply with their debt covenants, to repay, extend, or refinance their existing debt obligations and to obtain future credit will depend primarily on their operating performance. Williams’, Transco’s, and NWP’s ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If Williams, Transco, and NWP are unable to comply with these covenants, meet their debt service obligations, or obtain future credit on favorable terms, or at all, Williams, Transco, and NWP could be forced to restructure or refinance their indebtedness, seek additional equity capital or sell assets. Williams, Transco, and NWP may be unable to obtain financing or sell assets on satisfactory terms, or at all. Williams’, Transco’s, and NWP’s failure to comply with the covenants in the documents governing their indebtedness could result in events of default, which could render such indebtedness due and payable. Williams, Transco, and NWP may not have sufficient liquidity to repay their indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in each of Williams’, Transco’s, and NWP’s debt agreements could cause a default or acceleration to have a wider impact on their liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding debt agreements, please read Note 13 – Debt and Banking Arrangements. Changes to interest rates or increases in interest rates could adversely impact Williams’, Transco’s, and NWP’s access to credit, share price, and ability to issue securities or incur debt for acquisitions or other purposes, as applicable, and Williams’ ability to make cash dividends at intended levels. Interest rates have fluctuated in recent years but could increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing Williams’, Transco’s, and NWP’s financing costs to increase accordingly. As with other yield-oriented securities, Williams’ share price will be impacted by the level of Williams’ dividends and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in Williams’ shares, and a rising interest rate environment could have an adverse impact on Williams’ share price and Williams’ ability to issue equity or pay cash dividends at intended levels or Williams’, Transco’s, and NWP’s ability to incur debt. Williams’ hedging activities might not be effective and could increase the volatility of Williams’ results. In an effort to manage Williams’ financial exposure related to commodity price and market fluctuations, Williams has entered, and may in the future enter into, contracts to hedge certain risks associated with its assets and operations. In these hedging activities, Williams has used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While Williams attempts to manage counterparty credit risk within guidelines established by its credit policy, 44 Williams may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in Williams’ reported net income while the positions are open due to mark-to-market accounting. Access to capital could be affected by financial institutions’ policies concerning fossil fuel related businesses . Public concern regarding the potential effects of climate change has directed increased attention towards the funding sources of fossil-fuel energy companies. As a result, certain financial institutions, funds, and other sources of capital have restricted or eliminated their investment in certain market segments of fossil-fuel related energy. Ultimately, limiting fossil-fuel related companies’ access to capital could make it more difficult for Williams’, Transco’s, and NWP’s customers to secure funding for exploration and production activities or for Williams, Transco, and NWP to secure funding for growth projects. Such a lack of capital could also both indirectly affect demand for Williams’, Transco’s, and NWP’s services and directly affect their ability to fund construction or other capital projects. Williams can exercise substantial control over Transco’s and NWP’s distribution policies, businesses, and operations and may do so in a manner that is adverse to Transco’s and NWP’s interests . Because Transco and NWP are indirect wholly owned subsidiaries of Williams, Williams exercises substantial control over their businesses and operations and makes determinations with respect to, among other things, the following: • Payment of distributions and repayment of advances; • Decisions on financings and capital raising activities; • Mergers or other business combinations; • Acquisition or disposition of assets. Williams could decide to increase distributions or advances to Transco’s and NWP’s member consistent with existing debt covenants. This could adversely affect Transco’s or NWP’s liquidity.Risks Related to RegulationsThe operation of Williams’, Transco’s, and NWP’s businesses might be adversely affected by regulatory proceedings, including FERC proceedings; changes in government regulations or in their interpretation or implementation; or the introduction of new laws or regulations applicable to Williams’, Transco’s, and NWP’s businesses or customers. Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. In addition to regulation by other federal, state, and local regulatory authorities, interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:• Transportation and sale for resale of natural gas in interstate commerce;• Rates, operating terms, types of services, and conditions of service; • Certification and construction of new interstate pipelines and storage facilities; • Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities; • Accounts and records; • Depreciation and amortization policies; • Relationships with affiliated companies that are involved in marketing functions of the natural gas business; • Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on Williams’, Transco’s, and NWP’s pipelines and regulators have rights 45 to challenge the rates charged under certain circumstances. Any successful challenge could materially affect Williams’, Transco’s, and NWP’s results of operations. Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, Williams, Transco, and NWP cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against them, or other regulatory action, including legislation, which might be materially adverse to the operation of Williams’, Transco’s, and NWP’s businesses and results of operations or increase their operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against Williams, Transco, and NWP which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage their reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance. In addition, existing regulations, including those pertaining to financial assurances to be provided by Williams’, Transco’s, and NWP’s businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner that differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to Williams, Transco, and NWP, their customers, or their business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that Williams, Transco, and NWP transport, gather, process, and treat could decline, compliance costs could increase, and results of operations could be adversely affected. Williams’, Transco’s, and NWP’s operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose them to significant costs, liabilities, and expenditures that could exceed expectations. Williams’, Transco’s, and NWP’s operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal practices and construction activities, as applicable. New or amended environmental laws and regulations can also result in significant increases in capital costs incurred to comply with such laws and regulations. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all operations, and delays or denials in granting permits. Joint and several strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from Williams’, Transco’s, and NWP’s properties and facilities. Private parties, including the owners of properties through which Williams’, Transco’s, and NWP’s pipeline and gathering systems pass and facilities where their wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from their operations. Some sites at which Williams, Transco, and NWP operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites. Williams, Transco, and NWP are generally responsible for all liabilities associated with the environmental condition of their facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, Williams, Transco, and NWP could acquire, or be required to provide indemnification against, environmental liabilities that could expose them to material losses, which may not be covered by insurance. In addition, the steps Williams, Transco and 46 NWP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and Williams, Transco, and NWP might be required to shut down, divest, or alter the operation of those facilities, which might cause them to incur losses. In addition, regulations directed at preventing climate change and the costs that may be associated with such regulations and with the regulation of emissions of GHGs have the potential to affect the businesses of Williams, Transco, and NWP. Regulatory actions by the Environmental Protection Agency or the passage of new laws or regulations could result in increased costs to operate and maintain facilities, install new emission controls on facilities, or administer and manage any GHG emissions program. Williams, Transco, and NWP believe it is possible that future governmental legislation and/or regulation may require them either to limit GHG emissions associated with operations or to purchase allowances for such emissions. Williams, Transco, and NWP could also be subjected to a carbon tax assessed on the basis of carbon dioxide emissions or otherwise. However, Williams, Transco, and NWP cannot predict precisely what form these future regulations might take, the stringency of any such regulations or when they might become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require Williams, Transco, and NWP to reduce emissions or to purchase allowances for such emissions. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could make some of Williams’, Transco’s, and NWP’s activities uneconomic to maintain or operate. Williams, Transco, and NWP continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit and reduce GHG emissions from their facilities. Although the regulation of GHG emissions may have a material impact on Williams’, Transco’s, and NWP’s operations and rates, Williams, Transco, and NWP believe it is premature to attempt to quantify the potential costs of the impacts. If Williams, Transco, and NWP are unable to recover or pass through a significant level of costs related to complying with climate change regulatory requirements, it could have a material adverse effect on Williams’, Transco’s, and NWP’s results of operations and financial condition.General Risk FactorsWilliams, Transco, and NWP do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of their insurers to satisfy their claims. In accordance with customary industry practice, Williams, Transco, and NWP maintain insurance against some, but not all, risks and losses, and only at levels they believe to be appropriate. The occurrence of any risks not fully covered by Williams’, Transco’s, and NWP’s insurance could have a material adverse effect on their businesses, financial condition, results of operations, and cash flows and their ability to repay debt. Failure to attract and retain an appropriately qualified workforce could negatively impact Williams’, Transco’s, and NWP’s results of operations. Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, the challenges of attracting new, qualified workers to the midstream energy industry, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Transco and NWP have no employees; employees of Williams and its affiliates provide services. Williams’ failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Williams’, Transco’s, and NWP’s ability to manage and operate the businesses. If Williams is unable to successfully attract and retain an appropriately qualified workforce, including members of senior management, results of operations could be negatively impacted. 47 Holders of Williams’ common stock may not receive dividends in the amount expected or any dividends. Williams may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash Williams pays as a dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond Williams’ control, including: • The amount of cash that Williams’ subsidiaries distribute to it; • The amount of cash Williams generates from its operations, Williams’ working capital needs, Williams’ level of capital expenditures, and Williams’ ability to borrow; • The restrictions contained in Williams’ indentures and credit facility and Williams’ debt service requirements;• The cost of acquisitions, if any.A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of Williams’ stock price.

Item 7 · Management's Discussion & Analysis

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FY 2023-12-31 (earlier)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsGeneralWe are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Our operations are located in the United States. Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, compression and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas. Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following business activities: • Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas. • Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments. • West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, the Mid-Continent region which includes the Anadarko and Permian basins, and the DJ Basin of Colorado which includes RMM, a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023. This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II. • Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets. 49 Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.DividendsIn December 2023, we paid a regular quarterly dividend of $0.4475 per share. On January 30, 2024, our board of directors approved a regular quarterly dividend of $0.4750 per share payable on March 25, 2024. Overview of the Results of Operations Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2023, increased by $1.13 billion over the prior year. Further discussion of our results is found in this report in the Results of Operations.Recent DevelopmentsExpansion Project UpdatesSignificant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook. Northeast G&P Susquehanna Supply Hub Gathering Expansion We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Susquehanna region. We constructed approximately 22 miles of gathering pipeline and associated incremental compression. The system added incremental natural gas gathering capacity of 320 MMcf/d. This project went into service in the fourth quarter of 2023. Utica Shale Gathering Expansion We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Utica region on our Cardinal gathering system. We constructed approximately 30 miles of gathering pipeline and associated incremental compression. The system added incremental natural gas gathering capacity of 125 MMcf/d. Phase 1 of this project was placed into service in the third quarter of 2023 and Phase 2 went into service in the fourth quarter of 2023. Transmission & Gulf of Mexico Regional Energy Access In January 2023, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We placed approximately half of the project into service in the fourth quarter of 2023 and plan to place the remainder of the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d. Acquisitions and Divestitures (see Note 3 – Acquisitions and Divestitures) Gulf Coast Storage Acquisition On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP for $1.95 billion, subject to working capital and post-closing adjustments. The purpose of this acquisition was to expand our natural gas storage footprint in the Gulf Coast region, and will be reported in the Transmission & Gulf of 50 Mexico segment. The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration. DJ Basin Acquisitions On November 30, 2023, we closed on the acquisition of 100 percent of Cureton, whose operations are located in the DJ Basin, for $546 million, subject to working capital and post-closing adjustments. Concurrently, we closed on the acquisition of an additional 50 percent interest in our equity-method investment RMM for $704 million. We now own 100 percent of and consolidate RMM. The purpose of these acquisitions was to expand our gathering and processing footprint in the DJ Basin. The Cureton Acquisition was funded with cash on hand. Substantially all of the RMM purchase price is not due to the seller until the first quarter of 2025, does not accrue interest until the fourth quarter of 2024, and may be repaid early without penalty. These businesses are reported within the West segment. Sale of Certain Gulf Coast Liquids Pipelines On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million. As a result of this sale, we recorded a gain of $129 million in 2023 in our Transmission & Gulf of Mexico segment. MountainWest Acquisition On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt. The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado. This business is reported within the Transmission & Gulf of Mexico segment. Favorable Judgment Against Energy Transfer We have been involved in litigation since 2016 in Delaware Chancery Court with Energy Transfer Equity, L.P. (Energy Transfer) related to the Agreement and Plan of Merger with Energy Transfer, dated as of September 28, 2015. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. On September 21, 2022, the Delaware Chancery Court entered a final order and judgment awarding us a termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer appealed to the Delaware Supreme Court. The Delaware Supreme Court held oral argument en banc on July 12, 2023. On October 10, 2023, the Delaware Supreme Court issued an opinion affirming the Delaware Chancery Court ruling. On October 25, 2023, Energy Transfer filed a motion for reargument with the Delaware Supreme Court, which was denied. On November 28, 2023, we received a $627 million payment from Energy Transfer for the final order and judgment. On the same day, we paid attorney fees which had been incurred on a contingent fee basis. This resulted in a net gain of $534 million reported as Net gain from Energy Transfer litigation judgment in our Consolidated Statement of Income for the year ended December 31, 2023 (See Note 17 – Contingencies and Commitments). Northwest Pipeline FERC Rate Case Settlement On November 15, 2022, Northwest Pipeline received approval from the FERC for a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation. Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date. 51Company OutlookOur strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2024 includes a continued focus on earnings and cash flow growth. In 2024, our operating results are expected to benefit from the recent Gulf Coast Storage and DJ Basin acquisitions. We also anticipate increases resulting from Transmission & Gulf of Mexico expansion projects, including the Regional Energy Access project, and annual inflation-based rate increases across our gathering and processing business. These increases are partially offset by lower expected Gas & NGL Marketing Services results, the absence of realized hedge gains captured in 2023, and a decrease in expected volumes in the Appalachian Basin associated with a lower expected commodity price environment. We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Our growth capital and investment expenditures in 2024 are expected to be in a range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other segment ventures. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments. Potential risks and obstacles that could impact the execution of our plan include:• A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products; • Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects; • Counterparty credit and performance risk; • Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions; • Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes; • Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;• General economic, financial markets, or industry downturns, including increased inflation and interest rates;• Physical damages to facilities, including damage to offshore facilities by weather-related events;• Other risks set forth under Part I, Item 1A. Risk Factors in this report. 52Expansion ProjectsOur ongoing major expansion projects include the following: Transmission & Gulf of Mexico Deepwater Shenandoah Project In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the fourth quarter of 2024. Deepwater Whale Project In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024. Regional Energy Access In January 2023, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We placed approximately half of the project into service in the fourth quarter of 2023 and plan to place the remainder of the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d. Southside Reliability Enhancement In July 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 423 Mdth/d. Texas to Louisiana Energy Pathway In January 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity. Southeast Energy Connector In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the second quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d. 53 Commonwealth Energy Connector In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d. Alabama Georgia Connector In April 2023, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from our Station 85 pooling point in Alabama to customers in Georgia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 64 Mdth/d.Southeast Supply EnhancementWe plan to file an application with the FERC as early as the third quarter of 2024 for this project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. We plan to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,587 Mdth/d. Overthrust Westbound Compression Expansion In November 2023, we filed an application with the FERC for the project, which involves an expansion of MountainWest’s existing natural gas transmission system to provide incremental firm transportation capacity from multiple receipt points in Wamsutter, Wyoming to a delivery point in Opal, Wyoming. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 325 Mdth/d. Northeast G&P Cardinal Gathering Expansion We have an agreement in place with a third party to facilitate natural gas production growth in the Utica Shale region. We plan to construct approximately 8 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 125 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the third quarter of 2025.WestLouisiana Energy Gateway In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the second half of 2025. Haynesville Gathering Expansion In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication. The system, once constructed, will provide natural gas gathering services to the 54 third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project. This project is expected to go into service in the second half of 2025.Critical Accounting EstimatesThe preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations. Pension and Postretirement Obligations We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs. These estimates and assumptions involve significant judgment and actual results will likely be different than anticipated. Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans. The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption. Benefit Cost Benefit Obligation One- Percentage- Point Increase One- Percentage- Point Decrease One- Percentage- Point Increase One- Percentage- Point Decrease (Millions) Pension benefits: Discount rate $ 3 $ (4) $ (73) $ 85 Expected long-term rate of return on plan assets (11) 11 — — Cash balance interest crediting rate 5 (4) 54 (47) Other postretirement benefits: Discount rate (3) 4 (13) 16 Expected long-term rate of return on plan assets (3) 3 — — Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio. Our expected long-term rate of return on plan assets used for our pension plans was 5.17 percent in 2023. The 2023 actual return on plan assets for our pension plans was approximately 11.4 percent. The 10-year average rate of return on pension plan assets through December 2023 was approximately 6.4 percent. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans, which considers a yield curve of high-quality corporate bonds and the duration of the expected benefit cash flows of each plan. The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate. 55Results of OperationsConsolidated Overview The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2023 and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.Year Ended December 31,2023 $ Changefrom2022*% Change from2022* 2022 $ Changefrom2021*% Change from2021* 2021 (Millions)Revenues:Service revenues $ 7,026 +490 +7 % $ 6,536 +535 +9 % $ 6,001 Service revenues – commodity consideration 146 -114 -44 % 260 +22 +9 % 238 Product sales 2,779 -1,777 -39 % 4,556 +20 — % 4,536 Net gain (loss) from commodity derivatives 956 +1,343 NM (387) -239 -161 % (148) Total revenues 10,907 10,965 10,627Costs and expenses:Product costs 1,884 +1,485 +44 % 3,369 +562 +14 % 3,931 Net processing commodity expenses 151 -63 -72 % 88 +13 +13 % 101 Operating and maintenance expenses 1,984 -167 -9 % 1,817 -269 -17 % 1,548 Depreciation and amortization expenses 2,071 -62 -3 % 2,009 -167 -9 % 1,842 Selling, general, and administrative expenses 665 -29 -5 % 636 -78 -14 % 558 Gain on sale of business (129) +129 NM — — — % — Other (income) expense – net (30) +58 NM 28 -12 -75 % 16 Total costs and expenses 6,596 7,947 7,996 Operating income (loss) 4,311 3,018 2,631 Equity earnings (losses) 589 -48 -8 % 637 +29 +5 % 608 Other investing income (loss) – net 108 +92 NM 16 +9 +129 % 7 Interest expense (1,236) -89 -8 % (1,147) +32 +3 % (1,179) Net gain from Energy Transfer litigation judgment 534 +534 NM — — — % — Other income (expense) – net 99 +81 NM 18 +12 +200 % 6 Income (loss) before income taxes 4,405 2,542 2,073 Less: Provision (benefit) for income taxes 1,005 -580 -136 % 425 +86 +17 % 511 Income (loss) from continuing operations 3,400 2,117 1,562 Income (loss) from discontinued operations (97) -97 NM — — — % — Net income (loss) 3,303 2,117 1,562 Less: Net income (loss) attributable to noncontrolling interests 124 -56 -82 % 68 -23 -51 % 45 Net income (loss) attributable to The Williams Companies, Inc. $ 3,179 +1,130 +55 % $ 2,049 +532 +35 % $ 1,517_______ * + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.56 2023 vs. 2022Service revenues increased primarily due to:• Higher volumes from acquisitions at our Transmission & Gulf of Mexico segment; • Higher volumes and rates at our Northeast G&P segment; partially offset by • Lower rates, partially offset by higher volumes at our West segment. The net sum of Service revenues – commodity consideration , Product sales , Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses for our reportable segments (excludes Other) comprise our Commodity margins . Product sales and net realized gains and losses on commodity derivatives at our Other segment, which reflect sales related to our upstream operations, comprise Net realized product sale s. Service revenues – commodity consideration, which represent payments we receive in the form of commodities for processing services provided, decreased primarily due to lower NGL prices. Most of these NGL volumes are sold during the month processed and are offset within Product costs below. The Product sales decrease primarily consists of: • Lower marketing sales activities at our Gas & NGL Marketing Services segment; • Lower sales from upstream operations within Other; • Lower equity NGL sales prices primarily at our West and Transmission & Gulf of Mexico segments; • Lower system management gas sales primarily at our West and Transmission & Gulf of Mexico segments. As we are acting as agent for natural gas marketing customers, our natural gas marketing product sales are presented net of the related costs of those activities within our Gas & NGL Marketing Services segment. Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in our Gas & NGL Marketing Services, West, and Other segments (see Note 16 – Commodity Derivatives). We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream-related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs. The Product costs decrease primarily consists of: • Lower marketing activities at our Gas & NGL Marketing Services segment; • Lower costs associated with NGLs acquired as commodity consideration related to our equity NGL production activities; • Lower system management gas purchases primarily at our West and Transmission & Gulf of Mexico segments. Net processing commodity expenses increased primarily due to: • Unfavorable change in unrealized gains and losses from commodity derivatives related to processing plant shrink gas purchases (see Note 16 – Commodity Derivatives); 57 • Partially offset by lower natural gas purchases due to lower prices associated with our equity NGL production activities primarily at our West and Transmission & Gulf of Mexico segments. Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 2022 NorTex Asset Purchase, and increased scope and timing of operating and maintenance activities. Depreciation and amortization expenses increased primarily related to our upstream assets, and assets acquired in the February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 2022 NorTex Asset Purchase. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition. Selling, general, and administrative expenses increased primarily due to acquisition and transition-related costs associated with the MountainWest Acquisition. Gain on sale of business resulted from our sale of certain liquids pipelines in the Gulf Coast region (see Note 3 – Acquisitions and Divestitures). Other (income) expense – net within Operating income (loss) changed favorably primarily due to: • A favorable change associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and the absence of 2022 regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate; • The absence of a 2022 loss related to Eminence storage cavern abandonments; • A 2023 gain related to a contract settlement. Equity earnings (losses) changed unfavorably primarily due to a decrease at Laurel Mountain and our share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP, partially offset by increases at Blue Racer and OPPL. The favorable change in Other investing income (loss) – net includes higher interest income earned on higher cash and cash equivalent balances, and a gain on remeasuring our existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 3 – Acquisitions and Divestitures). The increase in Interest expense was primarily due to our 2023 debt issuances and MountainWest's long-term debt (see Note 12 – Debt and Banking Arrangements), partially offset by an increase in interest capitalized related to ongoing expansion projects. The Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of our complaint against Energy Transfer (see Note 17 – Contingencies and Commitments). The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in equity allowance for funds used during construction (equity AFUDC) at our Transmission & Gulf of Mexico segment and the related effects of deferred taxes within Other. Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of a benefit related to the release of valuation allowances on deferred income tax assets in 2022, a lower benefit associated with decreases in our estimate of the state deferred income tax rate in both periods, and the absence of 2022 federal income tax settlements. See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods. Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 17 – Contingencies and Commitments). 58 The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at Cardinal and the Northeast JV. 2022 vs. 2021 Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher volumes including from the Trace Acquisition and NorTex Asset Purchase, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses . Service revenues – commodity consideration increased primarily due to higher NGL prices, partially offset by lower NGL volumes. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below. Product sales increased primarily due to higher marketing sales prices and volumes, including increased volumes associated with the Sequent Acquisition in third-quarter 2021 and the Trace Acquisition in second-quarter 2022. Product sales also increased due to higher sales volumes and prices associated with our upstream operations and system management gas sales, as well as higher prices and lower volumes related to our equity NGL sales activities. These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities, including significant 2022 lower of cost or net realizable value adjustments to our natural gas inventory. The unfavorable change in Net gain (loss) from commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment. Lower net realized losses at our West segment and a net unrealized gain at our Other segment in 2022 partially offset these impacts. Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices and volumes associated with our NGL marketing activities, including the increase in volumes associated with the Trace Acquisition in second-quarter 2022, as well as significant 2022 lower of cost or net realizable value adjustments to our NGL inventory. Product costs also increased due to higher system management gas purchases and higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities. Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain from derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices. Operating and maintenance expenses increased primarily due to higher operating and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues. The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase. Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment. 59 Selling, general, and administrative expenses increased primarily due to higher employee-related expenses driven by the Sequent Acquisition in July 2021 and higher expenses for various corporate costs, including technology costs to support efforts to track and quantify emissions associated with natural gas procurement, transmission, and delivery. Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to charges related to Eminence storage cavern abandonments and monitoring, as well as regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations). Equity earnings (losses) changed favorably primarily due to increases at investments across our West segment, including RMM, and at Laurel Mountain, partially offset by a decrease at Appalachia Midstream Investments. Provision (benefit) for income taxes changed favorably primarily due to a benefit associated with a decrease in our estimate of the state deferred income tax rate, a benefit related to the release of a valuation allowance, and federal settlements, partially offset by higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods. The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at the Northeast JV. Year-Over-Year Operating Results – Segments We evaluate segment operating performance based upon Modified EBITDA . Note 18 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Net income (loss) . Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP. Transmission & Gulf of MexicoYear Ended December 31,2023 2022 2021(Millions)Service revenues $ 3,858 $ 3,579 $ 3,385 Service revenues – commodity consideration (1) 38 64 52 Product sales (1) 252 404 349 Net realized gain (loss) from commodity derivatives (1) 2 — — Segment revenues 4,150 4,047 3,786 Product costs (1) (246) (399) (349) Net processing commodity expenses (1) (13) (26) (17) Other segment costs and expenses (1,157) (1,141) (982) Gain on sale of business 129 — — Proportional Modified EBITDA of equity-method investments 205 193 183 Transmission & Gulf of Mexico Modified EBITDA $ 3,068 $ 2,674 $ 2,621 Commodity margins $ 33 $ 43 $ 35_______________ (1) Included as a component of Commodity margins .60 2023 vs. 2022 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues and a Gain on sale of business.Service revenues increased primarily due to:• A $222 million increase due to the acquisition of MountainWest primarily in transportation and storage revenues; • A $42 million increase due to the NorTex Asset Purchase primarily in storage and transportation revenues; • A $30 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower, partially offset by lower volumes from the Norphlet pipeline due to natural decline; • A $15 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023; • A $12 million increase in Transco’s and Northwest Pipeline’s revenues associated with short-term firm transportation; partially offset by • A $19 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline; • A $14 million decrease in reimbursable electric power costs and storage rates, offset by similar changes in electricity charges and storage costs, reflected in Other segment costs and expenses; • A $10 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 primarily in transportation revenues (see Note 3 – Acquisitions and Divestitures). Commodity margins decreased primarily due to a $15 million decrease from our equity NGLs, driven by unfavorable net realized pricing for equity NGL sales, partially offset by lower prices for natural gas purchases associated with our equity NGL production activities.Other segment costs and expenses increased primarily due to:• Higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase; and higher costs related to timing and scope of general maintenance activities primarily at Transco, partially offset by lower reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues ; and lower employee-related costs; • Higher project feasibility costs; partially offset by • Favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline associated with the FERC rate case settlement mentioned above in Service revenues and the absence of 2022 regulatory charges associated with decreases in Transco’s estimated deferred state income tax rate; • A favorable change in equity AFUDC as a result of increased capital expenditures at Transco; • The absence of losses related to Eminence storage cavern abandonments in 2022. Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures). 61 2022 vs. 2021 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues , partially offset by higher Other segment costs and expenses.Service revenues increased primarily due to:• A $163 million increase in Transco’s service revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021, park and loan services, short-term firm transportation, overall demand, and commodity fee revenues. Additionally, 2022 benefited from higher reimbursable electric power costs and storage rates effective since the second quarter of 2022, partially offset by lower cash out surcharges, all of which are offset by similar changes in electricity, storage and cash out charges reflected in Other segment costs and expenses; • A $21 million increase in the Eastern Gulf Coast region primarily due to higher production handling and gathering volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower production handling, gathering and transportation volumes from natural decline; • A $16 million increase primarily related to storage and transportation revenues due to the acquisition of NorTex in August 2022; partially offset by • A $13 million decrease in the Western Gulf Coast region primarily at Perdido due to lower transportation and gathering volumes from temporary downtime from producer operational issues in 2022. Commodity margins associated with our equity NGLs increased $5 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities. Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, partially offset by favorable cash out charges, all of which are offset by similar changes in electricity reimbursements, cash out charges, and storage revenues reflected in Service revenues. Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project; maintenance costs primarily related to general maintenance at Transco, Gulf Coast region, and Northwest Pipeline; charges related to Eminence storage cavern abandonments and monitoring; and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco. 62Northeast G&P Year Ended December 31,2023 2022 2021(Millions)Service revenues $ 1,896 $ 1,654 $ 1,528 Service revenues – commodity consideration (1) 5 14 7 Product sales (1) 132 134 99 Segment revenues 2,033 1,802 1,634 Product costs (1) (123) (135) (99) Net processing commodity expenses (1) (2) (3) (2) Other segment costs and expenses (566) (522) (503) Proportional Modified EBITDA of equity-method investments 574 654 682 Northeast G&P Modified EBITDA $ 1,916 $ 1,796 $ 1,712 Commodity margins $ 12 $ 10 $ 5(1) Included as a component of Commodity margins .2023 vs. 2022 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues , partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses .Service revenues increased primarily due to:• A $92 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation, processing, and gathering volumes as well as higher processing rates; • An $84 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations and higher volumes, partially offset by the absence of proceeds from the release of an acreage dedication in 2022; • A $61 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes. Other segment costs and expenses increased primarily due to increased scope of operations, a loss contingency accrual, and higher operating taxes. Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain due to lower commodity-based gathering rates, MVC, and volumes, and at Aux Sable Liquid Products LP primarily due to our $31 million share of a loss contingency accrual related to our 14 percent ownership. The decrease was partially offset by an increase at Blue Racer primarily driven by higher gathering and processing volumes. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering volumes and annual rate escalations at Marcellus South, partially offset by lower gathering rates resulting from annual cost of service contract redeterminations and lower volumes at the Bradford Supply Hub. 63 2022 vs. 2021 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues , partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses .Service revenues increased primarily due to:• A $64 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes as well as higher processing rates; • A $43 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations, as well as proceeds from the release of an acreage dedication; • A $14 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses; • No change in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, offset by lower gathering volumes. Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset in Service revenues . Proportional Modified EBITDA of equity-method investments decreased at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redeterminations as well as lower volumes. Additionally, there was a decrease at Blue Racer primarily due to lower volumes. The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates. 64West Year Ended December 31,2023 2022 2021(Millions)Service revenues $ 1,502 $ 1,542 $ 1,248 Service revenues – commodity consideration (1) 103 182 179 Product sales (1) 441 841 643 Net realized gain (loss) from commodity derivatives relating to service revenues 82 (1) (15) Net realized gain (loss) from commodity derivatives relating to product sales (1) 7 (3) (29) Net realized gain (loss) from commodity derivatives 89 (4) (44) Segment revenues 2,135 2,561 2,026 Product costs (1) (425) (813) (608) Net processing commodity expenses (1) (92) (105) (85) Other segment costs and expenses (542) (564) (477) Proportional Modified EBITDA of equity-method investments 162 132 105 West Modified EBITDA $ 1,238 $ 1,211 $ 961 Commodity margins $ 34 $ 102 $ 100________________ (1) Included as a component of Commodity margins .2023 vs. 2022 West Modified EBITDA increased primarily due to a favorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, higher Proportional Modified EBITDA of equity-method investments, and lower Other segment costs and expenses, partially offset by lower Commodity margins and Service revenues. Service revenues decreased primarily due to: • A $120 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing; • A $13 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues, partially offset by escalated gathering rates and higher gathering volumes; • A $6 million decrease associated with reimbursable compressor power and fuel purchases primarily due to lower prices, which are offset by similar changes in Other segment costs and expenses ; partially offset by • A $69 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from increased producer activity and the Trace Acquisition in April 2022, partially offset by lower rates driven by unfavorable commodity pricing; • A $25 million increase in the DJ Basin region primarily associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures); 65 • A $15 million increase in our other NGL operations associated with higher storage fees primarily due to a new contract as well as higher fractionation fees primarily due to higher volumes partially offset by lower rates from lower natural gas prices. Net realized gain (loss) from commodity derivatives relating to service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions. Commodity margins decreased $68 million primarily due a $46 million decrease from our equity NGLs and a $14 million decrease from other sales activities, both primarily due to lower net realized commodity pricing. Other segment costs and expenses decreased primarily due to a favorable change in our net imbalance liability due to changes in pricing, favorable contract settlements in first-quarter 2023, lower corporate allocations, and lower reimbursable compressor power and fuel purchases which are substantially offset in Service revenues. These items were partially offset by higher operating expenses related to operations including those acquired in the Trace Acquisition and the DJ Basin Acquisitions, lower system gains at Wamsutter, and a fourth quarter 2023 write-down of assets held for sale. Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL as well as higher volumes at RMM, partially offset by lower proportional results as RMM was consolidated as of November 30, 2023. 2022 vs. 2021 West Modified EBITDA increased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) from commodity derivatives, partially offset by higher Other segment costs and expenses.Service revenues increased primarily due to:• A $186 million increase in the Haynesville Shale region primarily due to higher gathering volumes including volumes from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing; • A $96 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing; • A $14 million increase associated with higher fractionation fees primarily due to higher fractionation volumes from a new contract; • A $4 million increase in the Eagle Ford Shale region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity; partially offset by • A $10 million decrease in the Wamsutter region primarily due to lower MVC revenue. Net realized gain (loss) from commodity derivatives relating to service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions. Product margins from our equity NGLs increased $6 million primarily due to higher net realized NGL sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGL production activities. Additionally, volumes of equity NGL sold and natural gas purchased associated with our equity NGL production activities were lower primarily due to a customer contract change. Margins from other sales activities increased $16 million primarily due to higher condensate sales and favorable pricing. Marketing margins decreased $20 million primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021. Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in 66 2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition, and an unfavorable change in our net imbalance liability due to changes in pricing. Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL and higher commodity prices and volumes at RMM.Gas & NGL Marketing Services Year Ended December 31,2023 2022 2021(Millions)Service revenues $ 1 $ 3 $ 3 Product sales (1) 2,060 3,534 4,292 Net realized gain (loss) from commodity derivative instruments (1) 115 17 25 Net unrealized gain (loss) from commodity derivative instruments 702 (321) (109) Net gain (loss) from commodity derivatives 817 (304) (84) Segment revenues 2,878 3,233 4,211Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses(43) 47 — Product costs (1) (1,786) (3,228) (4,152) Other segment costs and expenses (99) (92) (37) Gas & NGL Marketing Services Modified EBITDA $ 950 $ (40) $ 22 Commodity margins $ 389 $ 323 $ 165________________ (1) Included as a component of Commodity margins .2023 vs. 2022 Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and higher Commodity margins , partially offset by an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses . Commodity margins increased $66 million primarily due to: • A $65 million increase from our natural gas marketing operations including $129 million of higher natural gas storage marketing margins primarily driven by a favorable change of $111 million in lower of cost or net realizable value adjustment; and the absence of a $15 million charge related to the remaining recognition of a purchase accounting inventory fair value adjustment in 2022. The increase in our natural gas marketing margins was partially offset by $64 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads; • A $1 million increase in our NGL marketing margins including a $20 million favorable change in lower of cost or net realizable value inventory adjustments, partially offset by higher transportation and fractionation fees and an unfavorable change in net realized gains and losses on sale of inventory in 2023 compared to 2022 driven by an unfavorable change in NGL prices. Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022. 67 2022 vs. 2021 Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins . Commodity margins increased $158 million primarily due to: • A $188 million increase in natural gas marketing margins which included the following: ◦ A $301 million increase in natural gas transportation capacity marketing margins primarily resulting from the Sequent Acquisition in the third quarter of 2021 and an increase in favorable pricing spreads in 2022 compared to 2021; partially offset by ◦ A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021; ◦ A $55 million decrease in natural gas storage marketing margins due primarily to an increase in lower of cost or net realizable value inventory adjustments of $115 million and higher storage fees, partially offset by higher storage withdrawals in 2022 compared to 2021. • A $30 million decrease in our NGL marketing margins primarily due to lower of cost or net realizable value inventory adjustments in 2022. Net unrealized gain (loss) from commodity derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021. Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations.Other Year Ended December 31,2023 2022 2021(Millions)Service revenues $ 16 $ 24 $ 32 Product sales (1) 442 706 333 Net realized gain (loss) from commodity derivative instruments (1) 47 (104) (20) Net unrealized gain (loss) from commodity derivative instruments 1 25 — Net gain (loss) from commodity derivatives 48 (79) (20) Segment revenues 506 651 345 Other segment costs and expenses (197) (217) (167) Net gain from Energy Transfer litigation judgment 534 — — Proportional Modified EBITDA of equity-method investments (2) — — Other Modified EBITDA $ 841 $ 434 $ 178 Net realized product sales $ 489 $ 602 $ 313________________ (1) Included as a component of Net realized product sales .68 2023 vs. 2022 Other Modified EBITDA increased primarily due to the Net gain from Energy Transfer litigation judgmen t (see Note 17 – Contingencies and Commitments), partially offset by lower results from our upstream operations, which included the following: • $113 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production volumes from new wells in our Haynesville Shale region and higher crude oil production volumes from new wells in our Wamsutter region were partially offset by lower natural gas and NGL production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023; • A $24 million unfavorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022; partially offset by • An increase in Other segment costs and expenses associated with our upstream operations primarily due to increased production volumes and expenses related to severe winter weather in 2023, partially offset by lower associated ad valorem and production taxes, which were impacted by lower commodity prices and lower natural gas and NGL production volumes in our Wamsutter region. Other segment costs and expenses not associated with our upstream operations decreased primarily due to the absence of an $11 million charge related to an accrual for loss contingency in the third quarter of 2022 and a $19 million favorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction. 2022 vs. 2021 Other Modified EBITDA increased primarily due to $248 million higher results from our upstream operations which included the following: • A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of the favorable impact of Winter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from commodity derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021. Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021; • A $25 million favorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by • A $66 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated production taxes, which were also impacted by higher commodity prices and higher volumes as well as higher tax rates. Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in 2022, substantially offset by the absence of a $10 million charge related to an accrual for loss contingency in 2021. 69Management’s Discussion and Analysis of Financial Condition and Liquidity OverviewWe have continued to focus on earnings and cash flow growth, noting significant increases in both net income and cash provided by operating activities. During 2023, investing and financing expenditures included $2.5 billion of capital expenditures, $1.6 billion of acquisitions including MountainWest and Cureton, and $2.2 billion of dividends paid to common shareholders. These expenditures were funded in part by $5.9 billion of cash provided by operating activities (which includes a net $534 million related to our favorable Energy Transfer litigation outcome - see Note 17 – Contingencies and Commitments), and cash from borrowing activities of $2.5 billion. Our financial position also reflects the deferred consideration obligation for the RMM Acquisition (see Note 3 – Acquisitions and Divestitures). We ended the year with $2.150 billion of Cash and cash equivalents as reported on our Consolidated Balance Sheet. See also the following section titled Sources (Uses) of Cash .OutlookOur growth capital and investment expenditures in 2024 are currently expected to be in a range from $1.45 billion to $1.75 billion, excluding the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures). Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other segment ventures. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2024 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock. On January 5, 2024, we issued $2.1 billion in long-term debt (see Note 12 – Debt and Banking Arrangements). As of December 31, 2023, we have approximately $2.337 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.LiquidityBased on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2024. Our potential material internal and external sources and uses of liquidity are as follows:Sources: Cash and cash equivalents on hand Cash generated from operationsDistributions from our equity-method investees Utilization of our credit facility and/or commercial paper programCash proceeds from issuance of debt and/or equity securities Proceeds from asset monetizations Uses: Working capital requirements Capital and investment expenditures Product costs Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply Other operating costs including human capital expensesQuarterly dividends to our shareholders Repayments of borrowings under our credit facility and/or commercial paper programDebt service payments, including payments of long-term debt Distributions to noncontrolling interests Share repurchase program70 At December 31, 2023, we have approximately $23.376 billion of long-term debt due after one year. See Note 12 – Debt and Banking Arrangements for the aggregate maturities over the next five years. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations. Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook . At December 31, 2023, we had a working capital deficit of $1.317 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows: Available Liquidity December 31, 2023(Millions)Cash and cash equivalents $ 2,150 Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1) 3,025 $ 5,175__________(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had $725 million of commercial paper outstanding at December 31, 2023. The highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million. At December 31, 2023, we were in compliance with the financial covenants associated with our credit facility. See Note 12 – Debt and Banking Arrangements for additional information on our credit facility and commercial paper program.DividendsWe increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in each quarter of 2023.RegistrationsPrior to the expiration of our shelf registration statement, we anticipate filing a new shelf registration statement as a well-known seasoned issuer.Distributions from Equity-Method InvesteesThe organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities for our more significant equity-method investees.Credit RatingsThe interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:Rating Agency Outlook Senior Unsecured Debt RatingS&P Global Ratings Stable BBB Moody’s Investors Service Stable Baa2 Fitch Ratings Stable BBB These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current 71 criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.Sources (Uses) of CashThe following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):Cash Flow Year Ended December 31,Category 2023 2022 2021(Millions) Sources of cash and cash equivalents:Net cash provided (used) by operating activities Operating $ 5,938 $ 4,889 $ 3,945 Proceeds from long-term debt (see Note 12) Financing 2,755 1,755 2,155 Proceeds from (payments of) commercial paper - net Financing 372 345 — Proceeds from sale of business (see Note 3) Investing 346 — —Uses of cash and cash equivalents:Capital expenditures Investing (2,516) (2,253) (1,239) Common dividends paid Financing (2,179) (2,071) (1,992) Purchases of businesses, net of cash acquired (see Note 3) Investing (1,568) (933) (151) Payments of long-term debt (see Note 12) Financing (634) (2,876) (894) Dividends and distributions paid to noncontrolling interests Financing (213) (204) (187) Purchases of and contributions to equity-method investments (see Note 8) Investing (141) (166) (115) Purchases of treasury stock Financing (130) (9) — Other sources / (uses) – net Financing and Investing (32) (5) 16 Increase (decrease) in cash and cash equivalents $ 1,998 $ (1,528) $ 1,538Operating activitiesThe factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Net unrealized (gain) loss from commodity derivative instruments , Gain on sale of business, Inventory write-downs, and Amortization of stock-based awards. Our Net cash provided (used) by operating activities in 2023 increased from 2022 primarily due to higher operating income (excluding noncash items as previously discussed), as well as favorable changes in net operating working capital and margin requirements, partially offset by lower Distributions from equity-method investees . Our Net cash provided (used) by operating activities in 2022 increased from 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from equity-method investees , partially offset by net unfavorable changes in net operating working capital. Environmental We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingencies and Commitments). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with 72 unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $48 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2023. We will seek to recover approximately $3 million of accrued costs related to remediation activities by our interstate gas pipelines through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2023, we paid approximately $7 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $9 million in 2024 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2023, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compounds and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost these regulatory impacts at this time. We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas transmission pipelines. Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. 73

FY 2025-12-31 (later)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCombined Management’s Discussion and Analysis of Financial Condition and Results of Operations PageGeneral55 Company Outlook 58 Results of Operations 64 Williams 64 Transco 78 NWP 81 Management’s Discussion and Analysis of Financial Condition and Liquidity 83 General Williams is an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Its operations are located in the United States. Williams’ interstate natural gas pipeline strategy is to create value by maximizing the utilization of its pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Williams’ gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC. As such, Williams’ rates and charges for the transportation of natural gas in interstate commerce; the extension, expansion, or abandonment of jurisdictional facilities; and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but Williams may also negotiate rates with its customers pursuant to the terms of its tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of the cost of service is recovered through firm capacity reservation charges in transportation rates. The ongoing strategy of Williams’ midstream operations is to safely and reliably operate large-scale midstream infrastructure where its assets can be fully utilized and drive low per-unit costs. Williams focuses on consistently attracting new business by providing highly reliable service to its customers. These services include natural gas gathering and processing, treating, compression and storage; NGL fractionation, transportation and storage; and crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas. Consistent with the manner in which Williams’ CODM evaluates performance and allocates resources, Williams’ operations are conducted, managed, and presented within the following reportable segments: Transmission, Power & Gulf; Northeast G&P; West; and Gas & NGL Marketing Services. All remaining business activities, including upstream operations and corporate activities, are included in Other. See Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for a full description of each segment. Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to Williams’ current continuing operations and should be read in conjunction with the financial statements and combined notes thereto included in Part II, Item 8. Financial Statements and Supplementary Data of this report.DividendsIn December 2025, Williams paid a regular quarterly dividend of $0.500 per share. On January 27, 2026, Williams’ board of directors approved a regular quarterly dividend of $0.525 per share payable on March 30, 2026. 55 Table of Contents Management’s Discussion and Analysis (Continued) Overview of Year Ended December 31, 2025 Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2025, increased $393 million compared to the year ended December 31, 2024. Further discussion of the results is found in this report in the Results of Operations.Recent DevelopmentsTransco FERC Rate Case Filing On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement of its prior rate case. On September 30, 2024, the FERC issued an order accepting and suspending Transco’s general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The order also accepted rate decreases for certain services to be effective as of October 1, 2024. During the third quarter of 2025, Transco reached an agreement in principle with its customers and the other participants to settle all aspects of the rate case and has accrued a related liability for rate refunds. Transco filed with the FERC in October 2025 for approval of the settlement. On December 30, 2025, the FERC approved the settlement which will become effective March 1, 2026. Power Innovation Projects Williams continues to pursue projects to support the power demands created by new data center and industrial development in power grid-constrained markets, including agreements with a large, investment-grade company to provide onsite natural gas and power generation infrastructure. See Expansion Projects for further discussion. Sale of Mid-Continent Gathering Assets In December 2025, Williams’ management approved a plan to sell certain gas gathering assets in the Mid-Continent region. These operations were designated as held for sale at December 31, 2025 and an impairment, within the West segment, has been recognized for 2025. Sale of South Mansfield Upstream Interests In October 2025, Williams entered into an agreement to sell its interests in certain upstream ventures in the South Mansfield area of the Haynesville Shale region, included in Other, for consideration of $398 million with additional contingent consideration to possibly be received through 2029. The transaction closed in January 2026, and Williams expects to recognize a gain in the first quarter of 2026. Investments in Louisiana LNG and Driftwood Pipeline Projects In October 2025, Williams closed on various agreements with the same counterparty to acquire a 10 percent equity-method investment in Louisiana LNG, which is developing a fully permitted LNG export facility, and an 80 percent interest in Driftwood Pipeline, which is constructing a fully permitted greenfield pipeline, Line 200, connecting to multiple other pipelines, including Transco and Louisiana Energy Gateway, to supply the LNG facility. Williams will be the operator of the pipeline. The total initial purchase price was $378 million, and both investments will require additional capital to fund further construction. Williams will also manage the gas supply for the LNG facility and purchase approximately 10 percent of the LNG produced. Saber Asset Purchase In June 2025, Williams acquired 100 percent of Saber Midstream, LLC (Saber). The acquisition, which was accounted for as an asset purchase, included cash consideration of $47 million and the retention of $113 million of Saber’s debt, which was separately repaid in full within the same month. Saber operates a gas gathering system in the Haynesville Shale region in the West segment. 56 Table of Contents Management’s Discussion and Analysis (Continued) Cogentrix Investment In March 2025, Williams purchased a minority interest in Cogentrix for $153 million, which is accounted for as an equity-method investment within the Gas & NGL Marketing Services segment. Cogentrix owns interests in 11 natural gas power plants (see Note 8 – Investing Activities). Rimrock Asset Purchase On January 31, 2025, Williams purchased a group of natural gas gathering and processing assets from Rimrock Energy Partners, LLC (Rimrock) for approximately $325 million, to expand Williams’ gathering and processing footprint and create operational synergies in the DJ Basin in the West segment.Expansion Project UpdatesExpansion projects placed into service for the current year are described below. Ongoing major expansion projects are discussed later in Company Outlook. Transmission, Power & Gulf Overthrust Westbound Compression Expansion In October 2024, MountainWest received approval from the FERC for the project, which involves an expansion of MountainWest’s existing natural gas transmission system to provide incremental firm transportation capacity from multiple receipt points in Wamsutter, Wyoming to a delivery point in Opal, Wyoming. MountainWest placed the project into service in November 2025, increasing capacity by 325 Mdth/d. Stanfield South The project on NWP’s existing natural gas transmission system provides year-round transportation capacity from the Stanfield receipt point in Oregon to multiple delivery points in Idaho and a new delivery meter in Wyoming. NWP placed the project into service in November 2025, increasing NWP’s contracted capacity by 80 Mdth/d. Commonwealth Energy Connector In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. Transco placed the project into service in November 2025, increasing Transco’s capacity by 105 Mdth/d. Alabama Georgia Connector In March 2024, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s Station 85 pooling point in Alabama to customers in Georgia. Transco placed the project into service in October 2025, increasing Transco’s capacity by 64 Mdth/d. Deepwater Shenandoah Project In June 2021, Williams reached an agreement with two third parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands the existing Gulf of America offshore infrastructure connecting to a third-party offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing 57 Table of Contents Management’s Discussion and Analysis (Continued) facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids are now fractionated and marketed at Discovery’s Paradis plant in Louisiana. This project was placed into service in July 2025. Texas to Louisiana Energy Pathway In January 2024, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. Transco placed the project into service in April 2025. Under the project, Transco provides 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity. Southeast Energy Connector In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. Transco placed the project into service in April 2025, increasing Transco’s capacity by 150 Mdth/d. Deepwater Whale Project In August 2021, Williams reached an agreement with two third parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands its existing Western Gulf of America offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 124-mile oil pipeline from the Whale platform to Williams’ existing junction platform. This project was placed into service in January 2025. West Haynesville Gathering Expansion In February 2023, Williams announced its agreement with a third party to facilitate natural gas production growth in the Haynesville Shale basin for the construction of a greenfield gathering system in support of a 26,000-acre dedication. In April 2025, the third party sold a majority of their ownership interest to another party, with both third parties agreeing to long-term capacity commitments on Williams’ Louisiana Energy Gateway expansion project. This project was placed into service in September 2025, providing natural gas gathering services to both parties. Louisiana Energy Gateway In August 2024, Williams began construction activities on new natural gas gathering assets in the Haynesville Shale basin to increase delivery of natural gas to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project was placed into service in July and August 2025, increasing natural gas gathering capacity by 1.8 Bcf/d.Company OutlookWilliams’ strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. Williams accomplishes this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. Williams continues to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. Williams believes that accomplishing these goals will position it 58 Table of Contents Management’s Discussion and Analysis (Continued) to deliver safe, reliable, clean energy services to its customers and an attractive return to shareholders. Williams’ business plan for 2026 includes a continued focus on earnings and cash flow growth. In 2026, Williams’ operating results are expected to benefit from the continued growth in the Transmission, Power & Gulf segment, primarily reflecting the impacts of the Socrates Power Innovation project, as well as numerous expansion projects at Transco and the Gulf of America. Growth in 2026 will benefit from a full year of the Louisiana Energy Gateway expansion project as well as expected increases in Haynesville Shale volumes. Additionally, Williams expects higher gathering and processing results in the Northeast. These increases are partially offset by the divestiture of the South Mansfield upstream joint venture, and lower expected Eagle Ford results in our West segment related to minimum volume commitment reductions. Williams seeks to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Williams’ growth capital and investment expenditures in 2026 are expected to range from $6.1 billion to $6.7 billion, excluding acquisitions and certain long-lead time equipment for power innovation projects which are backed by reimbursement from the customer if the equipment order is cancelled. Growth capital spending in 2026 primarily includes the Power Innovation projects, Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Shale basin, and projects supporting the Northeast G&P business. Williams is investing capital in the Louisiana LNG and Driftwood Pipeline projects, as well as the development of its Wamsutter upstream oil and gas properties. In addition to growth capital and investment expenditures, Williams also remains committed to projects that maintain its assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments. See Note 18 – Contingencies and Commitments for further discussion of Williams’ commitments. Potential risks and obstacles that could impact the execution of Williams’ plan include:• A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products; • Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects; • Counterparty credit and performance risk; • Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions; • Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes; • Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;• General economic, financial markets, or industry downturns, including increased inflation, interest rates, or tariffs;• Physical damages to facilities, including damage to offshore facilities by weather-related events;• Other risks set forth under Part I, Item 1A. Risk Factors. 59 Table of Contents Management’s Discussion and Analysis (Continued)Expansion ProjectsWilliams’ ongoing major expansion projects include the following: Transmission, Power & Gulf Gillis West Transco plans to file a prior notice application with the FERC in 2026 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. Transco plans to place the project into service as early as the second quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 115 Mdth/d.Southeast Supply EnhancementIn January 2026, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. Transco plans to place the project into service as early as the third quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,597 Mdth/d. Northeast Supply Enhancement In August 2025, the FERC issued an order granting Transco’s petition for reissuance of the certificate authorization for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s Compressor Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. In October and November 2025, Transco’s applications for Clean Water Act and related permits with the states of Pennsylvania, New York and New Jersey were approved. In August 2025, Transco executed precedent agreements with customers subscribing to all of the capacity under the project. Transco plans to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth ⁄ d. Pine Prairie Phase IV Expansion In August 2025, Williams filed a certificate application with the FERC for the project, which will involve an expansion of storage capacity and the injection and withdrawal capabilities of one of its existing storage facilities in the Gulf Coast region. Williams plans to place the project into service during the fourth quarter of 2028, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase working gas storage capacity by 10 Bcf. Dalton Lateral II Transco plans to file a certificate application for the project with the FERC in 2027. The project involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s main line near existing Station 115 to an existing power plant in Georgia. Transco plans to place the project into service as early as the fourth quarter of 2029, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity up to 460 Mdth/d. Power Express Transco plans to file an application with the FERC as early as the second quarter 2027 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm 60 Table of Contents Management’s Discussion and Analysis (Continued) transportation capacity in Virginia. Transco plans to place the project into service as early as the third quarter of 2030, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 689 Mdth/d. Naughton Coal-to-Gas Conversion The project involves an expansion of NWP’s existing natural gas transmission system to provide year-round transportation capacity to a power plant in southwest Wyoming. NWP plans to place the project into service as early as the second quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 98 Mdth/d. Ryckman Creek Loop In January 2026, NWP received approval from the FERC for the project, which involves an expansion of NWP’s existing natural gas transmission system to provide incremental firm transportation capacity from a receipt point in northeast Oregon to multiple delivery points in southwest Wyoming. NWP plans to place the project into service as early as the fourth quarter of 2026. The project is expected to increase capacity by 50 Mdth/d. Huntingdon Connector NWP plans to file a prior notice application for the project with the FERC in the first quarter of 2026. The project involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the Sumas receipt point to various delivery points in Washington. NWP plans to place the project into service during the fourth quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 78 Mdth/d. Wild Trail In May 2025, NWP filed a certificate application with the FERC for the project, which involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the White River Hub receipt point in western Colorado to various delivery points in southwest Wyoming and southern Colorado. The Wild Trail project is fully subscribed by an affiliate of NWP. NWP plans to place the project into service during the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 83 Mdth/d. Kelso-Beaver Reliability In November 2025, NWP received approval from the FERC for the project. The Kelso-Beaver Reliability project on NWP’s existing natural gas transmission system will provide year-round transportation capacity to various receipt and delivery points in Oregon. NWP plans to place the project into service during the fourth quarter of 2028, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 183 Mdth/d. Power Innovation Socrates Williams has received approval from the Ohio Power Siting Board for the power generation facilities and is expecting final approval for the associated gas pipeline infrastructure in the first half of 2026. The Socrates project involves the construction of the Socrates North and South power generation facilities in New Albany, Ohio. Williams has agreed to provide committed power generation and associated gas pipeline infrastructure for the project, which is expected to provide a combined 400 megawatts of onsite power generation capacity to the customer. The project is backed by a 10 year, primarily fixed-price power 61 Table of Contents Management’s Discussion and Analysis (Continued) purchase agreement, with an option for the customer to extend the term of the agreement. Williams plans to place the project into service in the third and fourth quarter of 2026, assuming timely receipt of permits. Additional Projects Williams has agreed to provide committed power generation and associated gas pipeline infrastructure for three additional Power Innovation projects, Apollo, Aquila and Socrates the Younger. The projects are backed by primarily fixed-price power purchase agreements, with options for the customer to extend the term of the agreements. The Apollo project, in Ohio, has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027. The Aquila project, in Utah, also has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027 and the first half of 2028. The Socrates the Younger project, in Ohio, has a term of 10 years, and Williams expects the project to be placed into service the second half of 2028. All expected in-service dates assume timely receipt of permits.WestDorne Williams will construct and operate a greenfield treating and dehydration facility with a capacity of 400 MMcf/d. This project is expected to be placed into service in the third quarter of 2027.Critical Accounting EstimatesPreparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. The nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on the financial condition or results of operations. Regulatory Accounting Williams’ regulated interstate natural gas pipelines, including Transco and NWP, are regulated by the FERC. Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Certain incurred costs and obligations are recorded as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for operations that are regulated and apply the provisions of ASC 980 can differ from the accounting requirements for nonregulated operations. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, levelized cost of service, employee-related benefits, environmental costs, negative salvage, asset retirement obligations (AROs), as well as other costs and taxes included in, or expected to be included in, future rates. Management has determined that for its rate-regulated entities, it is appropriate to apply the accounting prescribed by ASC 980 and, accordingly, the accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, any of Williams’ regulated interstate natural gas pipelines, including Transco or NWP, ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the respective 62 Table of Contents Management’s Discussion and Analysis (Continued) balance sheet and included in the respective statement of income for the period in which the discontinuance of regulatory accounting treatment occurs and can be estimated, unless otherwise required to be recorded under other provisions of U.S. generally accepted accounting principles. The aggregate amount of regulatory assets reflected on Williams’ Consolidated Balance Sheet was $698 million at December 31, 2025, of which Transco’s and NWP’s Balance Sheets reflected $394 million and $83 million, respectively. The aggregate amount of regulatory liabilities reflected on Williams’ Consolidated Balance Sheet was $1.3 billion at December 31, 2025, of which Transco’s and NWP’s Balance Sheets reflected $1.0 billion and $245 million, respectively. A summary of regulatory assets and liabilities is included in Note 10 – Regulatory Assets and Liabilities. 63 Table of Contents Management’s Discussion and Analysis (Continued)Results of OperationsWilliams’ Consolidated Overview The following table and discussion is a summary of Williams’ consolidated results of operations for the three years ended December 31, 2025, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.Year Ended December 31,2025 $ Changefrom2024*% Change from2024* 2024 $ Changefrom2023*% Change from2023* 2023 (Dollars in millions)Revenues:Service revenues $ 8,348 +720 +9 % $ 7,628 +602 +9 % $ 7,026 Product sales and service revenues – commodity consideration 3,482 +357 +11 % 3,125 +200 +7 % 2,925 Net gain (loss) from commodity derivatives 120 +370 NM (250) -1,206 NM 956 Total revenues 11,950 10,503 10,907Costs and expenses:Product costs and net processing commodity expenses 2,199 -81 -4 % 2,118 -83 -4 % 2,035 Operating and maintenance expenses 2,282 -103 -5 % 2,179 -195 -10 % 1,984 Depreciation, depletion, and amortization expenses 2,347 -128 -6 % 2,219 -148 -7 % 2,071 General and administrative expenses 721 -13 -2 % 708 -43 -6 % 665 Impairment or write-off of certain assets 212 -212 NM — +10 +100 % 10 Gain on sale of business — — — — -129 -100 % (129) Other (income) expense – net (7) -53 -88 % (60) +20 +50 % (40) Total costs and expenses 7,754 7,164 6,596 Operating income (loss) 4,196 3,339 4,311 Equity earnings (losses) 760 +200 +36 % 560 -29 -5 % 589 Other investing income (loss) – net 42 -301 -88 % 343 +235 NM 108 Interest expense (1,442) -78 -6 % (1,364) -128 -10 % (1,236) Net gain from Energy Transfer litigation judgment — — — — -534 -100 % 534 Other income (expense) – net 69 -39 -36 % 108 +9 +9 % 99 Income (loss) before income taxes 3,625 2,986 4,405 Less: Provision (benefit) for income taxes 857 -217 -34 % 640 +365 +36 % 1,005 Income (loss) from continuing operations 2,768 2,346 3,400 Income (loss) from discontinued operations — — — — +97 +100 % (97) Net income (loss) 2,768 2,346 3,303 Less: Net income attributable to noncontrolling interests 150 -29 -24 % 121 +3 +2 % 124 Net income (loss) attributable to The Williams Companies, Inc. $ 2,618 +393 +18 % $ 2,225 -954 -30 % $ 3,179_______ * + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.64 Table of Contents Management’s Discussion and Analysis (Continued) 2025 vs. 2024Service revenues increased primarily due to:• Higher revenues associated with expansion projects at the Transmission, Power & Gulf and the West segments; • Increased Transco transportation and storage rates and Gulf Coast Storage rates at the Transmission, Power & Gulf segment; • Higher volumes from the August 2024 Discovery Acquisition at the Transmission, Power & Gulf segment, the June 2025 Saber Asset Purchase and the January 2025 Rimrock Asset Purchase at the West segment, and higher volumes from the Northeast JV at the Northeast G&P segment; • Higher revenues associated with reimbursable expenses primarily in the Northeast G&P segment, which is offset by similar changes in the charges reflected in Operating and maintenance expenses ; partially offset by • Lower revenues in the Eagle Ford Shale region due to lower MVC revenue at the West segment. The net sum of Product sales and service revenues – commodity consideration , Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for processing plants for the reportable segments comprise Commodity Margins . Service revenues - commodity consideration represent payments received in the form of commodities for processing services provided. Most of these commodity volumes are sold during the month processed and are offset within Product costs and net processing commodity expenses . The sum of Product sales and net realized gains and losses on commodity derivatives related to the upstream operations comprise Net realized product sales . The Product sales and service revenues – commodity consideration increase primarily consists of: • Higher product sales from upstream operations primarily related to higher volumes, including the November 2024 Crowheart Acquisition (See Note 3 – Acquisitions and Divestitures), and natural gas prices at Other; • Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment; • Higher marketing sales activities primarily related to higher net gas marketing sales activities, partially offset by lower NGL marketing sales activities at the Gas & NGL Marketing Services segment; • Higher cash-out activity primarily at the Transmission, Power & Gulf segment. As Williams is acting as agent for natural gas marketing customers, its natural gas marketing product sales are presented net of the related costs of those activities within the Gas & NGL Marketing Services segment. Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services segment, as well as upstream operations at Other (see Note 17 – Commodity Derivatives). Williams experiences significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage capacity portfolios as well as upstream-related production. However, the unrealized fair value measurement gains and losses on the derivatives are generally offset by valuation changes in the economic value of the underlying production or transportation and storage capacity contracts, which are not recognized until the underlying transaction occurs. 65 Table of Contents Management’s Discussion and Analysis (Continued) The Product costs and net processing commodity expenses increase primarily consists of: • Higher shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment; • Higher cash-out activity primarily at the Transmission, Power & Gulf segment; partially offset by • Lower marketing activities primarily related to NGL’s at the Gas & NGL Marketing Services segment. Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other, and higher electricity and fuel primarily in the Northeast G&P segment (substantially offset by higher Service revenues discussed above), partially offset by the absence of the impact of a 2024 change in practice related to payroll timing. Depreciation, depletion, and amortization expenses increased primarily related to assets acquired and expansion projects placed in-service at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other and an increase in Transco depreciation rates associated with the rate case at the Transmission, Power & Gulf segment, partially offset by lower ARO-related depreciation at the Transmission, Power & Gulf segment. General and administrative expenses increased due to higher employee-related costs, partially offset by lower acquisition and transition costs primarily at the Transmission, Power & Gulf segment and the absence of the impact of a 2024 change in a practice related to payroll timing. Impairment or write-off of certain assets includes an impairment to certain assets held for sale in the Mid-Continent region and the write-off of certain DJ Basin region assets in the West segment in 2025. The unfavorable change in Other (income) expense – net within Operating income (loss) includes net unfavorable changes to charges and credits associated with amortization of regulatory assets and liabilities related to the Transco rate case and deferral of ARO-related depreciation at the Transmission, Power & Gulf segment. Equity earnings (losses) changed favorably primarily due to the impact of $153 million from our investment Cogentrix in 2025 (see Note 8 – Investing Activities) and increases at Blue Racer and Appalachia Midstream Investments. The unfavorable change in Other investing income (loss) – net includes the absence of a $149 million gain on the sale of our interests in Aux Sable in 2024 (see Note 8 – Investing Activities), a $127 million gain on remeasurement of our existing equity-method investment associated with the purchase of the remaining interest in Discovery in 2024, and lower interest income earned on lower cash and cash equivalent balances. Interest expense was primarily impacted by 2024 and 2025 debt issuances, partially offset by 2024 and 2025 debt retirements and the absence of imputed interest on deferred consideration obligations related to previous acquisitions (see Note 13 – Debt and Banking Arrangements). The unfavorable change in Other income (expense) – net below Operating income (loss) includes a decrease in equity AFUDC primarily as a result of the timing of capital projects within the regulated businesses. Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income and the absence of a benefit associated with a decrease in the estimate of the state deferred income tax rate in 2024. See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods. 66 Table of Contents Management’s Discussion and Analysis (Continued) 2024 vs. 2023 Service revenues increased primarily due to: • Higher volumes from the November 2023 DJ Basin Acquisitions at the West segment and the January 2024 Gulf Coast Storage, August 2024 Discovery, and February 2023 MountainWest Acquisitions at the Transmission, Power & Gulf segment; partially offset by lower volumes from the September 2023 sale of certain liquids pipelines at the Transmission, Power & Gulf segment (see Note 3 – Acquisitions and Divestitures), • Higher revenues associated with expansion projects at the Transmission, Power & Gulf segment, partially offset by • Lower gathering volumes at the West and Northeast G&P segments. The Product sales and service revenues – commodity consideration increase primarily consists of: • Higher marketing sales activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing sales activities related to NGLs at the Gas & NGL Marketing Services segment, primarily related to activity associated with the sale certain liquids pipelines. Net natural gas marketing sales were impacted by higher storage costs; partially offset by • Lower system management gas sales primarily at the Transmission, Power & Gulf segment; • Lower product sales from upstream operations; partially offset by higher volumes from the November 2024 Crowheart Acquisition at Other; • Lower equity NGL sales and commodity consideration revenues associated with NGL production activity primarily at the West segment; partially offset by higher activity in the Transmission, Power & Gulf segment primarily due to the Discovery Acquisition. Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services and West segments, and upstream operations at Other. The Product costs and net processing commodity expenses increase primarily consists of: • Higher marketing activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing activities primarily related to NGLs at the Gas & NGL Marketing Services segment; partially offset by • Lower shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily at the West segment. Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the West and Transmission, Power & Gulf segments; as well as unfavorable changes in employee-related costs, including the impact of a change in a practice related to payroll timing; and the net imbalance liability due to changes in pricing. Depreciation, depletion, and amortization expenses increased primarily related to the assets acquired at the Transmission, Power & Gulf and West segments and an increase at Transco related to additional assets placed in service. The increase is partially offset by lower amortization of intangibles related to the acquisition of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (Sequent) in 2021. 67 Table of Contents Management’s Discussion and Analysis (Continued) General and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a practice related to payroll timing, partially offset by lower acquisition and transition-related costs associated with the MountainWest Acquisition (see Note 3 – Acquisitions and Divestitures). Gain on sale of business reflects a gain from the sale of certain liquids pipelines in the Transmission, Power & Gulf segment in 2023. Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission, Power & Gulf segment; partially offset by the absence of a 2023 gain related to a contract settlement. Equity earnings (losses) changed unfavorably primarily due to the impacts of the consolidation of RMM and Discovery, and the sale of the interests in Aux Sable (see Note 8 – Investing Activities), partially offset by the absence of the share of a loss contingency accrual in 2023 at Aux Sable and favorable results at OPPL. Other investing income (loss) – net includes gains on the sale of the interests in Aux Sable and the gain on remeasuring the existing equity-method investment in Discovery to fair value with the acquisition of the remaining 40 percent ownership, partially offset by the absence the 2023 gain on remeasuring the existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 8 – Investing Activities). The increase in Interest expense was primarily due to Williams’ 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to the DJ Basin and Gulf Coast Storage Acquisitions, partially offset by 2023 and 2024 debt retirements. Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of Williams’ complaint against Energy Transfer in 2023 (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income and a higher benefit associated with decreases in the estimate of the state deferred income tax rate in both periods. Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the accrued liability associated with the Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Period-Over-Period Operating Results – Williams’ Segments Williams’ CODM evaluates segment operating performance based upon Modified EBITDA . Note 19 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Income (loss) before income taxes . Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of Williams’ assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP. 68 Table of Contents Management’s Discussion and Analysis (Continued) Transmission , Power & GulfYear Ended December 31,2025 2024 2023(Millions)Service revenues $ 4,826 $ 4,246 $ 3,858 Product sales and service revenues – commodity consideration (1) 616 382 290 Net realized gain (loss) from commodity derivatives (1) 1 — 2 Segment revenues 5,443 4,628 4,150 Product costs and net processing commodity expenses (1) (549) (329) (259) Other segment costs and expenses (1,321) (1,199) (1,157) Gain on sale of business — — 129 Proportional Modified EBITDA of equity-method investments 147 173 205 Transmission, Power & Gulf Modified EBITDA $ 3,720 $ 3,273 $ 3,068 Commodity margins $ 68 $ 53 $ 33_______________ (1) Included as a component of Commodity margins .2025 vs. 2024 Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.Service revenues increased primarily due to:• A $291 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Regional Energy Access in August 2024, Southside Reliability Enhancement in November 2024, Texas Louisiana Energy Pathway in April 2025, and Southeast Energy Connector in April 2025; and transportation and storage rate increases; • A $96 million increase in the Western Gulf Coast region primarily due to higher natural gas gathering and crude oil transportation volumes from the Whale expansion project that went in-service in January 2025; • A $78 million increase primarily in natural gas gathering revenues due to the Discovery Acquisition and volumes from the Shenandoah expansion project that went in-service in July 2025 (see Note 3 – Acquisitions and Divestitures); • A $49 million increase in the Eastern Gulf Coast region primarily due to higher production handling, crude oil transportation and natural gas gathering volumes from new wells at Gulfstar One in the Pickerel field and at Blind Faith in the Ballymore field and the absence of shut-ins due to weather-related events, partially offset by shut-ins for maintenance activities at Devils Tower impacting the Taggart and Kodiak fields; • A $45 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates; • A $14 million increase in NWP’s revenues primarily due to transportation rate increases. Commodity margins increased primarily due to the Discovery Acquisition. 69 Table of Contents Management’s Discussion and Analysis (Continued)Other segment costs and expenses increased primarily due to:• Unfavorable change in equity AFUDC primarily as a result of the timing of capital projects within the regulated businesses; • Net unfavorable changes in charges and credits associated with regulatory assets and liabilities related to the rate case at Transco; • Higher operating expenses and administrative costs including increased operating costs resulting from the Discovery Acquisition, corporate allocations, and property taxes, as well as higher employee-related costs, partially offset by the absence of acquisition and transition costs related to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures) and a 2024 change in a practice related to payroll timing; • Unfavorable change in the deferral of ARO-related depreciation at Transco; partially offset by • A net favorable change related to certain asset retirements in the Western Gulf Coast region in 2025. Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as Discovery was consolidated following its August 2024 acquisition. 2024 vs. 2023 Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by the absence of a Gain on sale of business, higher Other segment costs and expenses, and lower Proportional Modified EBITDA of equity-method investments.Service revenues increased primarily due to:• A $220 million increase primarily in storage revenues due to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures); • A $121 million increase in Transco’s revenues primarily associated with expansion projects and higher park and loan services; • A $41 million increase primarily in gathering revenues due to the Discovery Acquisition in August 2024; • A $38 million increase in primarily transportation and storage revenues due to the MountainWest Acquisition in February 2023 (see Note 3 – Acquisitions and Divestitures); • A $22 million increase in NorTex’s revenues primarily associated with higher storage rates; partially offset by • A $39 million decrease primarily in transportation revenues due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures); • A $34 million decrease in the Eastern Gulf region primarily due to shut-ins for producer operational issues at Gulfstar One in the Gunflint and Tubular Bells fields and weather-related events, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field. Other segment costs and expenses increased primarily due to: • Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to Williams’ Gulf Coast Storage and Discovery Acquisitions, and employee-related costs, including the impact of a change in a practice related to payroll timing; partially offset by significantly 70 Table of Contents Management’s Discussion and Analysis (Continued) lower acquisition and transition costs related to Williams’ MountainWest Acquisition, contract services at Transco, and operating costs related to the sale of certain liquids pipelines in the Gulf Coast region; • Unfavorable change in the amortization of regulatory pension liabilities at Transco; partially offset by • Lower project feasibility costs; • A favorable change in equity AFUDC primarily as a result of increased capital expenditures at Williams’ regulated businesses. Commodity margins increased primarily due to a $19 million increase from Williams’ equity NGLs primarily due to the Discovery Acquisition. Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023. Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as Discovery was consolidated.Northeast G&P Year Ended December 31,2025 2024 2023(Millions)Service revenues $ 1,995 $ 1,913 $ 1,896 Product sales and service revenues – commodity consideration (1) 173 112 137 Segment revenues 2,168 2,025 2,033 Product costs and net processing commodity expenses (1) (149) (88) (125) Other segment costs and expenses (631) (581) (566) Proportional Modified EBITDA of equity-method investments 640 602 574 Northeast G&P Modified EBITDA $ 2,028 $ 1,958 $ 1,916 Commodity margins $ 24 $ 24 $ 12(1) Included as a component of Commodity margins .2025 vs. 2024 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments , partially offset by higher Other segment costs and expenses.Service revenues increased primarily due to:• A $40 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation volumes, higher gathering volumes, and higher processing rates; • A $29 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses ; • An $11 million increase in gathering revenues in the Utica Shale region primarily related to higher volumes at Cardinal; partially offset by 71 Table of Contents Management’s Discussion and Analysis (Continued) • A $6 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates. Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel (substantially offset by higher Service revenues discussed above) and higher maintenance expenses. The increase was partially offset by lower employee-related costs related to the absence of the impact of a 2024 change in a practice related to payroll timing. Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by escalated gathering rates and higher gathering volumes, at Blue Racer primarily due to higher volumes and annual rate escalations, and at Laurel Mountain primarily due to higher commodity-based gathering rates and higher volumes. The increase was partially offset by a decrease at Aux Sable Liquid Products LP due to the sale of Williams’ investment in the third quarter of 2024. 2024 vs. 2023 Northeast G&P Modified EBITDA increased primarily due to higher Proportional Modified EBITDA of equity-method investments , higher Service revenues , and higher Commodity margins , partially offset by higher Other segment costs and expenses.Service revenues increased primarily due to:• A $20 million increase in revenues at the Northeast JV primarily related to higher gathering volumes as well as higher transportation & fractionation, gathering, and processing rates, partially offset by lower transportation & fractionation and processing volumes; • A $16 million increase in joint venture operating fees primarily related to assuming operatorship of Blue Racer effective January 1, 2024, (which is significantly offset by higher Other segment costs and expenses discussed below); • An $11 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses ; partially offset by • A $19 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates; • A $16 million decrease in gathering revenues in the Utica Shale region primarily related to lower volumes at Flint and Cardinal partially offset by escalated rates. Commodity margins increased due to a restructured gas purchase deal in 2024 which allowed for margin gain on residue pricing and liquids from fixed recoveries. In addition, Williams was not significantly impacted by system constraints which impacted margins in 2023. Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a practice related to payroll timing, as well as higher operating expenses, including higher electricity and fuel, and increased support costs related to assuming operatorship of Blue Racer effective January 1, 2024 (substantially offset by higher Service revenues discussed above). The increase was partially offset by lower maintenance expenses and the absence of the 2023 loss contingency accrual. Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the absence of Williams’ $31 million share of a loss contingency accrual related to its former ownership in 2023, as well as the terms of the new product marketing agreement, partially offset by the sale of Williams’ investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia 72 Table of Contents Management’s Discussion and Analysis (Continued) Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes and higher expenses.West Year Ended December 31,2025 2024 2023(Millions)Service revenues $ 1,851 $ 1,718 $ 1,502 Product sales and service revenues – commodity consideration (1) 992 947 544 Net realized gain (loss) from commodity derivatives relating to service revenues 2 10 82 Net realized gain (loss) from commodity derivatives relating to product sales (1) 2 (6) 7 Net realized gain (loss) from commodity derivatives 4 4 89 Segment revenues 2,847 2,669 2,135 Product costs and net processing commodity expenses (1) (876) (844) (517) Other segment costs and expenses (663) (645) (532) Impairment or write-off of certain assets (212) — (10) Proportional Modified EBITDA of equity-method investments 142 132 162 West Modified EBITDA $ 1,238 $ 1,312 $ 1,238 Commodity margins $ 118 $ 97 $ 34________________ (1) Included as a component of Commodity margins .2025 vs. 2024 West Modified EBITDA decreased primarily due to the 2025 Impairment or write-off of certain assets, partially offset by higher Service revenues.Service revenues increased primarily due to:• A $121 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from Louisiana Energy Gateway which was placed into service in third-quarter 2025 and the Saber Asset Purchase; • A $60 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase; • A $17 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing; partially offset by • A $77 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue. Commodity margins increased $21 million primarily due to $12 million higher margins from equity NGLs associated with higher net realized NGL sales prices as well as higher volumes of equity NGL sold, and a $12 million increase in marketing margins primarily associated with the DJ Basin Acquisitions, as previously discussed. Other segment costs and expenses increased primarily due to higher operating expenses associated with the Rimrock Asset Purchase. 73 Table of Contents Management’s Discussion and Analysis (Continued) Impairment or write-off of certain assets reflects the $176 million impairment of Mid-Continent assets held for sale, and $36 million write-off of certain compression and processing assets in the DJ Basin region. Proportional Modified EBITDA of equity-method investments increased primarily due to higher rates and volumes at OPPL. 2024 vs. 2023 West Modified EBITDA increased primarily due higher Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses, an unfavorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, and lower Proportional Modified EBITDA of equity-method investments. Service revenues increased primarily due to: • A $249 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures); • A $35 million increase in other NGL operations associated with higher fractionation and transportation revenue due to higher volumes and higher storage fees primarily due to a new contract; • A $14 million increase in the Wamsutter region primarily associated with higher gathering volumes from increased producer activity as well as higher volumes associated with the absence of weather-related events in first-quarter 2023; • A $12 million increase associated with reimbursable compressor power and fuel purchases primarily due to the DJ Basin Acquisitions as previously discussed, which are offset by similar changes in Other segment costs and expenses ; partially offset by • A $45 million decrease in the Haynesville Shale region primarily due to lower gathering volumes from decreased producer activity, partially offset by higher gathering rates; • A $31 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues; • A $24 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing and lower gathering volumes. Net realized gain (loss) from commodity derivatives relating to service revenues reflects an unfavorable change in settled commodity prices relative to Williams’ natural gas hedge positions. Commodity margins increased $63 million primarily due to $39 million higher margins associated with the DJ Basin Acquisitions, as previously discussed. Margins also increased $21 million from Williams’ equity NGLs primarily due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with equity NGL production activities; partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices. Other segment costs and expenses increased primarily due to higher operating and employee-related expenses including those resulting from the DJ Basin Acquisitions, as previously discussed, the absence of favorable contract settlements in first-quarter 2023, an unfavorable change in Williams’ net imbalance liability due to changes in pricing, higher reimbursable compressor power and fuel purchases which are offset in Service revenues , and the impact of a change in a practice related to payroll timing; partially offset by higher system gains and the absence of a fourth quarter 2023 write-down of assets held for sale. Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated related to the DJ Basin Acquisitions, as previously discussed, partially offset by higher volumes and higher commodity prices at OPPL. 74 Table of Contents Management’s Discussion and Analysis (Continued)Gas & NGL Marketing Services Year Ended December 31,2025 2024 2023(Millions)Service revenues $ — $ — $ 1 Product sales (1) 2,106 2,052 2,060 Net realized gain (loss) from commodity derivative instruments (1) (69) 72 115 Net unrealized gain (loss) from commodity derivative instruments 138 (335) 702 Net gain (loss) from commodity derivatives 69 (263) 817 Segment revenues 2,175 1,789 2,878 Product costs (1) (1,811) (1,799) (1,786)Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses2 (6) (43) Other segment costs and expenses (91) (108) (99) Proportional Modified EBITDA of equity-method investments 36 — — Gas & NGL Marketing Services Modified EBITDA $ 311 $ (124) $ 950 Commodity margins $ 226 $ 325 $ 389________________ (1) Included as a component of Commodity margins .2025 vs. 2024 Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments and higher Proportional Modified EBITDA of equity-method investments , partially offset by lower Commodity margins . Commodity margins decreased $99 million primarily due to: • An $83 million decrease in natural gas marketing margins, including $105 million of lower natural gas transportation capacity marketing margins due to unfavorable net realized pricing spreads. The decrease in natural gas marketing margins was partially offset by $22 million of higher natural gas storage marketing margins primarily driven by higher withdrawals in 2025 compared to 2024, partially offset by less favorable realized derivative gains; • A $16 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2025 compared to 2024 driven by an unfavorable change in NGL prices. Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2024 is primarily due to a change in forward commodity prices relative to hedge positions in 2025 compared to 2024. Other segment costs and expenses de creased primarily due to lower employee-related costs. Proportional Modified EBITDA of equity-method investments increased due to the March 2025 investment in Cogentrix. 75 Table of Contents Management’s Discussion and Analysis (Continued) 2024 vs. 2023 Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments and lower Commodity margins . Commodity margins decreased $64 million primarily due to: • A $44 million decrease in natural gas marketing margins including $35 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads. The decrease in natural gas marketing margins also includes $9 million of lower natural gas storage marketing margins primarily driven by higher storage fees and less favorable realized derivative gains, partially offset by a favorable change of $14 million in lower cost or net realizable value inventory adjustment; • A $20 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices. Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2023 primarily due to a change in forward commodity prices relative to hedge positions in 2024 compared to 2023.Other Year Ended December 31,2025 2024 2023(Millions)Service revenues $ 16 $ 15 $ 16 Product sales (1) 580 420 442 Net realized gain (loss) from derivative instruments (1) 36 35 47 Net unrealized gain (loss) from derivative instruments 10 (26) 1 Net gain (loss) from commodity derivatives 46 9 48 Net revenues from upstream operations, corporate, and other business activities. 642 444 506 Other costs and expenses (266) (209) (197) Net gain from Energy Transfer litigation judgment — — 534 Proportional Modified EBITDA of equity-method investments — 2 (2) Modified EBITDA from upstream operations, corporate, and other business activities $ 376 $ 237 $ 841 Net realized product sales $ 616 $ 455 $ 489________________ (1) Included as a component of Net realized product sales .76 Table of Contents Management’s Discussion and Analysis (Continued) 2025 vs. 2024 Modified EBITDA from upstream operations, corporate, and other business activities increased primarily due to: • A $161 million increase in Net realized product sales from upstream operations consisting of a $143 million increase at the Wamsutter region and an $18 million increase at the Haynesville Shale region. The Wamsutter region increased primarily due to higher production volumes, including from the November 2024 Crowheart Acquisition, and higher net realized natural gas prices, partially offset by lower net realized oil and NGL prices. The Haynesville region benefited from higher net realized natural gas prices, partially offset by lower production volumes, associated with South Mansfield production in the Haynesville Shale region; • A $36 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions; partially offset by • A $57 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024, and an unfavorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction. 2024 vs. 2023 Modified EBITDA from upstream operations, corporate, and other business activities decreased primarily due to: • A $34 million decrease in Net realized product sales from upstream operations primarily due to lower volumes and lower net realized commodity prices associated with Williams’ South Mansfield production in the Haynesville Shale region, and lower net realized commodity prices associated with Williams’ Wamsutter region. These decreases were partially offset by higher production volumes associated with Williams’ Wamsutter region production, including from the Crowheart Acquisition in the fourth quarter of 2024. • A $27 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions in 2024 compared to 2023; • A $12 million unfavorable change in other costs and expenses primarily related to upstream operations; and • The absence of a 2023 gain related to a favorable ruling on the final order and judgment of Williams’ complaint against Energy Transfer reflected in Net gain from Energy Transfer litigation judgment (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). 77 Table of Contents Management’s Discussion and Analysis (Continued) Transco - Results of Operations Year Ended December 31, 2025 $ Change from 2024* % Change from 2024* 2024 (Millions) Revenues: Natural gas transportation service revenues $ 2,874 +255 +10 % $ 2,619 Natural gas storage service revenues 228 +28 +14 % 200 Natural gas product sales 126 +8 +7 % 118 Other service revenues 35 +8 +30 % 27 Total revenues 3,263 2,964 Costs and expenses: Natural gas product costs 126 -8 -7 % 118 Operating and maintenance expenses 509 +1 — % 510 Depreciation and amortization expenses 574 -29 -5 % 545 General and administrative expenses 223 -7 -3 % 216 Taxes, other than income taxes 114 -3 -3 % 111 Other (income) expense – net 27 -62 NM (35) Total costs and expenses 1,573 1,465 Operating income (loss) 1,690 +191 +13 % 1,499 Interest expense (332) -8 -2 % (324) Interest income 37 -21 -36 % 58 Allowance for equity and borrowed funds used during construction (AFUDC) 35 -53 -60 % 88 Other income (expense) – net (4) +4 +50 % (8) Net income (loss) $ 1,426 +113 +9 % $ 1,313 _______ * + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. 2025 vs. 2024 Variances due to the changes in natural gas prices and transportation volumes have little impact on revenues because, under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in Transco’s transportation rates. Transco has cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, Transco may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, Transco transports gas on various pipeline systems, which may deliver 78 Table of Contents Management’s Discussion and Analysis (Continued) different quantities of gas on Transco’s behalf than the quantities of gas received from Transco. These transactions result in gas transportation and exchange imbalance receivables and payables. Transco’s tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on Transco’s operating income. Revenues increased primarily due to: • An increase in Natural gas transportation service revenues primarily due to additional capacity from placing the following projects into service: ◦ The Regional Energy Access Expansion in August 2024; ◦ The Southside Reliability Enhancement in November 2024; ◦ The Texas Louisiana Energy Pathway in April 2025; ◦ The Southeast Energy Connector in April 2025; ◦ The Commonwealth Energy Connector in November 2025; and ◦ The Alabama Georgia Connector in November 2025. The increase in Natural gas transportation service revenues is also due to transportation rate increases effective March 1, 2025, and higher seasonal services, partially offset by one less billing day in 2025, a decrease in short-term firm transportation, and lower electric power costs in 2025. Electric power costs are recovered from Transco’s customers through transportation rates and are offset in Operating and maintenance expenses resulting in no net impact on Transco’s results of operations. • An increase in Natural gas storage service revenues primarily due to an increase in rates. • An increase in Natural gas product sales due to higher cash-out pricing, partially offset by lower volumes, which directly offsets in Natural gas product costs resulting in no net impact on our results of operations. • An increase in Other service revenues due to higher park and loan services. Natural gas product costs changed unfavorably, directly offsetting Natural gas product sales and resulting in no net impact on our results of operations. Operating and maintenance expenses remained consistent year over year primarily due to an increase in employee-related costs offset by the absence of a 2024 change in payroll policy and lower electric power costs. Electric power costs are recovered from customers through transportation rates and are offset in Natural gas transportation service revenues resulting in no net impact on results of operations. Depreciation and amortization expenses increased due to rate increases effective March 1, 2025, as well as assets added from projects placed into service, partially offset by a decrease in ARO related depreciation (offset in Other income (expense) – net resulting in no net impact on Transco’s results of operations). General and administrative expenses increased due to higher corporate allocations and employee-related costs, partially offset by the absence of a 2024 change in payroll policy. Other (income) expense – net changed unfavorably primarily driven by changes in charges and credits associated with the rate case at Transco, and an unfavorable change in the deferral of ARO-related depreciation (offset in Depreciation and amortization expenses resulting in no net impact on Transco’s results of operations). 79 Table of Contents Management’s Discussion and Analysis (Continued) Interest income decreased primarily due to a decrease in affiliated interest income associated with advances to Williams. Allowance for equity and borrowed funds used during construction (AFUDC) decreased as a result of lower capital expenditures. 80 Table of Contents Management’s Discussion and Analysis (Continued) NWP - Results of Operations Year Ended December 31, 2025 $ Change from 2024* % Change from 2024* 2024 (Millions) Revenues: Natural gas transportation service revenues $ 434 $ +18 +4 % $ 416 Natural gas storage service revenues 15 — — % 15 Other service revenues 9 -4 -31 % 13 Total revenues 458 444 Costs and expenses: Operating and maintenance expenses 96 -1 -1 % 95 Depreciation and amortization expenses 117 -6 -5 % 111 General and administrative expenses 49 +2 +4 % 51 Taxes, other than income taxes 15 -1 -7 % 14 Other (income) expense - net (13) -5 -28 % (18) Total costs and expenses 264 253 Operating income (loss) 194 +3 +2 % 191 Interest expense (28) — — % (28) Allowance for equity and borrowed funds used during construction (AFUDC) 9 -1 -10 % 10 Other income (expense) – net 6 -1 -14 % 7 Net income (loss) $ 181 $ +1 +1 % $ 180 _______ * + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. 2025 vs. 2024 Variances due to changes in natural gas prices and transportation volumes have little impact on revenues because, under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in NWP’s transportation rates. Revenues increased primarily due to: • An increase in Natural gas transportation service revenues primarily due to rate increases effective April 1, 2025, and an increase in long-term firm transportation, partially offset by one less billing day in 2025 and a decrease in short-term firm transportation; • Partially offset by a decrease in Other service revenues from lower park and loan services. Depreciation and amortization expenses increased due to additional assets placed in service. 81 Table of Contents Management’s Discussion and Analysis (Continued) General and administrative expenses decreased primarily due to the absence of lease termination expense incurred in the prior year. Other (income) expense - net decreased primarily due to the recognition of a regulatory liability to be returned to rate payers for excess deferred income taxes. Allowance for equity and borrowed funds used during construction (AFUDC) decreased as a result of lower capital expenditures. 82 Table of Contents Management’s Discussion and Analysis (Continued)Management’s Discussion and Analysis of Financial Condition and Liquidity OverviewWilliams During 2025, investing and financing expenditures included $4.9 billion of capital expenditures, including the Rimrock, Saber, and Driftwood Pipeline asset purchases as well as Power Innovation projects; $2.4 billion of dividends paid to common shareholders; and $0.5 billion of investments in unconsolidated affiliates, including Cogentrix and Louisiana LNG. These expenditures were funded primarily by $5.9 billion of cash provided by operating activities and $2.4 billion of net borrowing activity in 2025. Williams ended the year with $63 million of Cash and cash equivalents . See also the following section titled Sources (Uses) of Cash . The June 2025 Saber Asset Purchase included the retention of $113 million of Saber’s debt, which was separately repaid in full within the same month. On January 3, 2025, Williams paid the remaining $100 million of the Gulf Coast Storage Acquisition purchase price obligation (see Note 3 – Acquisitions and Divestitures).OutlookWilliams’ growth capital and investment expenditures in 2026 are expected to range from $6.1 billion to $6.7 billion, as previously discussed in Company Outlook. On January 8, 2026, Williams issued $2.8 billion of long-term debt (see Note 13 – Debt and Banking Arrangements). As of December 31, 2025, Williams, including consolidated subsidiaries, had $1.3 billion of long-term debt due within one year. Williams’ potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, the credit facility, or the commercial paper program, as well as proceeds from asset monetizations.LiquidityWilliams expects to have sufficient liquidity to manage its businesses in 2026 based on forecasted levels of cash flow from operations and other sources of liquidity. Williams’ potential material internal and external sources and uses of liquidity are as follows: 83 Table of Contents Management’s Discussion and Analysis (Continued)Sources: Cash and cash equivalents on hand Cash generated from operationsDistributions from equity-method investees Utilization of the credit facility and/or commercial paper programCash proceeds from issuance of debt and/or equity securities Proceeds from asset monetizations Uses: Working capital requirements Capital and investment expenditures Product costs Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply Other operating costs including human capital expensesQuarterly dividends to shareholders Repayments of borrowings under the credit facility and/or commercial paper programDebt service payments, including payments of long-term debt Distributions to noncontrolling interests Share repurchase programAs of December 31, 2025, Williams had $27.3 billion of long-term debt due after one year. Potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, the credit facility, the commercial paper program, and proceeds from asset monetizations. Potential risks associated with Williams’ planned levels of liquidity discussed above include those previously discussed in Company Outlook . As of December 31, 2025, Williams had a working capital deficit of $2.9 billion, including cash and cash equivalents and long-term debt due within one year. As discussed above, Williams issued $2.8 billion of long-term debt in January 2026. Williams’ available liquidity is as follows: December 31, 2025(Millions)Cash and cash equivalents $ 63 Capacity available under Williams’ $3,750 million credit facility, less amounts outstanding under Williams’ $3,500 million commercial paper program (1) 3,050 $ 3,113__________(1) In managing its available liquidity, Williams does not expect a maximum outstanding amount in excess of the capacity of its credit facility inclusive of any outstanding amounts under its commercial paper program. Williams had $700 million of Commercial paper outstanding at December 31, 2025. Through December 31, 2025, the highest amount outstanding under the commercial paper program and credit facility during 2025 was $898 million. Williams expects to be in compliance with the financial covenants associated with the credit facility for the December 31, 2025, reporting period.DividendsWilliams increased the regular quarterly cash dividend to common stockholders by approximately 5 percent from $0.475 per share paid in each quarter of 2024, to $0.500 per share paid in each quarter of 2025. On January 27, 2026, Williams’ board of directors approved a regular quarterly dividend of $0.525 per share payable on March 30, 2026. 84 Table of Contents Management’s Discussion and Analysis (Continued)RegistrationsIn February 2024, Williams filed a shelf registration statement as a well-known seasoned issuer.Distributions from Equity-Method InvesteesThe organizational documents of entities in which Williams has an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities for our more significant equity-method investees.Credit RatingsThe interest rates at which Williams is able to borrow money are impacted by its credit ratings, which are currently as follows:Rating Agency Outlook Senior Unsecured Debt RatingS&P Global Ratings Stable BBB+ Moody’s Investors Service Positive Baa2 Fitch Ratings Positive BBB These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold Williams securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign Williams investment-grade ratings even if it meets or exceeds their current criteria for investment-grade ratios. A downgrade of its credit ratings might increase Williams’ future cost of borrowing and, if ratings were to fall below investment-grade, could require it to provide additional collateral to third parties, negatively impacting Williams’ available liquidity. 85 Table of Contents Management’s Discussion and Analysis (Continued)Sources (Uses) of CashThe following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented in Williams’ Consolidated Statement of Cash Flows:Cash Flow Year Ended December 31,Category 2025 2024 2023(Millions) Sources of cash and cash equivalents:Net cash provided (used) by operating activities Operating $ 5,898 $ 4,974 $ 5,938 Proceeds from long-term debt (Note 13) Financing 4,940 3,594 2,755 Proceeds from commercial paper – net Financing 245 — 372 Proceeds from dispositions of equity-method investments (Note 8) Investing — 161 — Proceeds from sale of business ( Note 3 ) Investing — — 346Uses of cash and cash equivalents:Capital expenditures Investing (4,893) (2,573) (2,516) Common dividends paid Financing (2,442) (2,316) (2,179) Payments of long-term debt Financing (2,827) (2,946) (634) Purchases of and contributions to equity-method investments Investing (511) (114) (141) Dividends and distributions paid to noncontrolling interests Financing (259) (242) (213) Purchases of businesses, net of cash acquired ( Note 3 ) Investing (1) (2,244) (1,568) Payments of commercial paper – net Financing — (269) — Purchases of treasury stock Financing — — (130) Other sources / (uses) – net Financing and Investing (147) (115) (32) Increase (decrease) in cash and cash equivalents $ 3 $ (2,090) $ 1,998Operating activitiesThe factors that determine Williams’ operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation, depletion, and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Net unrealized (gain) loss from commodity derivative instruments , Gain on sale of business , Impairment or write-off of certain assets , Gain on disposition of equity-method investments , Gain on remeasurement of equity-method investments , Inventory write-downs, and Amortization of stock-based awards. Williams’ Net cash provided (used) by operating activities in 2025 increased from 2024 primarily due to higher operating income (excluding noncash items previously discussed), along with favorable changes in margin requirements. Williams’ Net cash provided (used) by operating activities in 2024 decreased from 2023 primarily due to unfavorable changes in margin requirements, lower operating income (excluding noncash items previously discussed), and unfavorable changes in net operating working capital. 86 Table of Contents