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Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.18pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.11pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.25pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
litigation+1
unable+1
decline+1
penalty+1
prolonged+1
Positive rising
desirable+2
greater+1
beautiful+1
Risk Factors (Item 1A)
12,055 words
Item 1A. Risk Factors
You should carefully consider each of the following risks and all the other information contained in this Annual Report on Form 10-K in evaluating us and our common stock. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. Our business, financial condition, results of operations and cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common stock could decline. We have in the past been adversely affected by certain of, and may in the future be affected by, these risks.
Business and Operational Risks
Our financial results are affected by volatile refining margins, which are dependent on factors beyond our control.
Our operating results, cash flows, future rate of growth, the carrying value of our assets and our ability to execute share repurchases and pay our dividend at intended levels are highly dependent on the margins we realize on our refined products. Historically, refined product margins have been volatile, and we believe they will continue to be volatile. Our margins from the sale of refined products are influenced by a number of conditions, including the price of crude oil and other feedstocks. The prices of feedstocks and the prices at which we can sell our refined products fluctuate independently due to a variety of regional and global market factors that are beyond our control, including:
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
divestiture+7
absence+4
loss+1
late+1
obsolescence+1
Positive rising
gain+3
strong+2
stable+1
positive+1
benefitting+1
MD&A (Item 7)
15,384 words
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business, results of operations and financial condition should also be read in conjunction with the information included under Item 1. Business, Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data.
EXECUTIVE SUMMARY
Business Update
Our Refining & Marketing segment results for 2025 versus 2024 reflect higher realized refining margins supported by stable demand and by gasoline and distillate inventory levels in the U.S. that were at or below five-year averages. Longer term, global demand growth is expected to outpace the net impact of refining capacity additions and rationalizations through the end of the decade. We anticipate these fundamentals, as well as the U.S. refining industry’s current structural advantages over the rest of the world, will support a constructive environment for U.S. refiners.
Our Midstream segment contributed results and continued growth in 2025, from the expansion of its Permian to Gulf Coast natural gas and NGL value chains with the Northwind Midstream Acquisition and the BANGL Acquisition, progression of long-haul pipeline growth projects and expansion of Gulf Coast fractionation and export facilities. We believe our Midstream business is well positioned and has significant to support the development plans of its producer customers.
• global and regional inventory levels and availability of and demand for feedstocks and refined products;
• transportation infrastructure cost and availability;
• temporary and permanent closures, utilization levels and capacities of other refineries in our markets and globally;
• global and regional development by competitors of new refining or renewable conversion capacity;
• natural gas and electricity availability and supply costs;
• global and domestic political instability, threatened or actual terrorist incidents, armed conflict, economic activity and growth levels or lack thereof or other global political or economic conditions;
• tariffs on goods, including crude oil and other feedstocks, imported into the United States;
• local weather conditions; and
• the occurrence of other risks described herein.
Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refined product margins are uncertain. We generally purchase our feedstocks weeks before we refine them and sell the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks can have a significant effect on our financial results. We also purchase refined products manufactured by others for resale to our customers. Price changes during the periods between purchasing and reselling those refined products can have a material and adverse effect on our business, financial condition, results of operations and cash flows.
Lower refined product margins, including renewable diesel margins have in the past, and may in the future, lead us to reduce the amount of refined products we produce, which may reduce our revenues, income from operations and cash flows. Significant reductions in refined product margins could require us to reduce our capital expenditures, impair the carrying value of our assets (such as property, plant and equipment, inventory or goodwill), and require us to re-evaluate our capital allocation priorities, including our share repurchase activity, capital spending and dividends.
Industry, market, technological and regulatory developments regarding emissions, fuel efficiency and alternative fuel vehicles may decrease demand for liquid transportation fuels.
Developments aimed at reducing vehicle emissions, increasing vehicle efficiency or reducing the sale of new internal combustion engine vehicles may decrease the demand and may increase the cost for our liquid transportation fuels. Government mandates or incentives, industry and technological developments and consumer sentiment with respect to liquid transportation fuels may alter fuels or energy preferences or make alternative fuel vehicles more desirable and result in greater market penetration of such vehicles or otherwise decrease demand for our liquid transportation fuels. For example, the federal government through NHTSA and the EPA promulgate rules that require vehicle manufacturers to increase the fuel efficiency standards of liquid transportation fuels vehicles. The EPA has finalized a rule that reduces its current vehicle standards by eliminating regulation of GHG emissions. The new, reduced standards have been challenged in court.
In addition, California and several states have adopted regulations that require increased sales of electric vehicles. California, in particular, has passed several regulations mandating electric vehicles. These regulations include Advanced Clean Cars (“ACC”) I, ACC II, and Advanced Clean Trucks. The ACC II and Advanced Clean Trucks regulations are currently not enforceable in absence of federal waivers, but California filed litigation to reinstate the waivers.
Moreover, consumer acceptance and market penetration of electric, hybrid and alternative fuel vehicles continues to increase. In 2021, several automobile manufacturers jointly announced their shared goal that 40-50 percent of their new vehicle sales be battery electric, fuel cell or plug-in hybrid vehicles by 2030. Other automobile manufacturers have similar, or more aggressive, goals with respect to vehicle electrification. Technological breakthroughs relating to renewable fuels or other fuel alternatives
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such as hydrogen or ammonia, or efficiencyimprovements for internal combustion engines could reduce demand for liquid transportation fuels.
Together, these developments have had and are expected to continue to have an adverse effect on sales of our liquid transportation fuels, which in turn could have a material and adverse effect on our business, financial condition, results of operations and cash flows.
Our operations are subject to business interruptions and present inherent hazards and risks, which could adversely impact our results of operations and financial condition.
Our operations are subject to business interruptions, such as scheduled and unscheduled refinery turnarounds, unplanned maintenance, explosions, fires, refinery or pipeline releases, product quality incidents, power outages, severe weather, labor disputes, acts of terrorism, or other natural or man-made disasters. These types of incidentsadversely affect our operations and may result in serious personal injury or loss of human life, significant damage to property and equipment, impaired ability to manufacture our products, environmental pollution, and substantial losses. We have experienced certain of these incidents in the past.
For assets located near populated areas, the level of damage resulting from these incidents could be greater. In addition, we operate in and adjacent to environmentally sensitive waters where tanker, pipeline, rail car and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Certain of our refineries receive crude oil and other feedstocks by tanker or barge. MPLX operates a fleet of boats and barges to transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks to and from our refineries and terminals. Transportation and storage of crude oil, other feedstocks and refined products over and adjacent to water involves inherent risk and subjects us to the provisions of the OPA-90 and state laws in U.S. coastal and Great Lakes states and states bordering inland waterways on which we operate, as well as international laws in the jurisdictions in which we operate. If we are unable to promptly and adequately contain any accident or discharge involving tankers, pipelines, rail cars or above ground storage tanks transporting or storing crude oil, other feedstocks or refined products, we may be subject to substantial liability. In addition, the service providers contracted to aid us in a discharge response may be unavailable due to weather conditions, governmental regulations or other local or global events.
Damages resulting from an incident involving any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially substantial claims or in our being assessed potentially substantial fines by governmental authorities.
We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers.
We are increasingly dependent on our information technology systems and those of our third-party business partners and service providers for the safe and effective operation of our business. We rely on such systems to process, transmit and store electronic information, including financial records and personal data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, credit card payments and authorizations at certain of our customers’ retail outlets, financial transactions, banking and numerous other processes and transactions.
Our information systems (and those of our third-party business partners and service providers), including our cloud computing environments and operational technology environments, are subject to numerous and evolving cybersecurity threats and attacks, including ransomware and other malware, phishing and social engineering schemes, supply chain attacks, and advanced artificial intelligence attacks, which can compromise our ability to operate, and the confidentiality, availability, and integrity of data in our systems or those of our third-party business partners and service providers. These and other cybersecurity threats may originate with criminal attackers, advanced persistentthreats and nation-state actors, state-sponsored actors, or employee error or malfeasance. Cybersecurity threat actors also may attempt to exploitvulnerabilities in software, including software commonly used by companies in cloud-based services and bundled software. Because the techniques used to obtain unauthorized access, or to disable or degrade systems, continuously evolve and some have become increasingly complex and sophisticated, and can remain undetected for a period of time despite efforts to detect and respond in a timely manner, we (and our third-party business partners and service providers) are subject to the risk of cyberattacks and cybersecurity incidents.
Our cybersecurity and infrastructure protection technologies, disaster recovery plans and systems, employee training and vendor risk management may not be sufficient to defend us against all unauthorized attempts to access our information or impact our systems. We and our third-party vendors and service providers have been and may in the future be subject to cybersecurity events and incidents of varying degrees. To date, the impacts of prior events and incidents have not had a material adverse effect on us.
Cybersecurity incidents involving our information technology systems or those of our third-party business partners and service providers can result in theft, destruction, loss, misappropriation or release of confidential financial data, personal data, intellectual property and other information; give rise to remediation or other expenses; result in litigation, claims and increased regulatory review, investigations, or scrutiny; reduce our customers’ willingness to do business with us; disrupt our operations and the services we provide to customers; and subject us to litigation and legal liability under international, U.S. federal and state laws.
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Any of such results could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.
Increasing regulatory focus on and expanding laws related to data privacy issues could expose us to increased liability, subject us to lawsuits, investigations, reputational harm and increase costs and restrictions on our operations that could significantly and adversely affect our business.
Along with our own data and information collected in the normal course of our business, we, and some of our third-party service providers, collect, use, transfer and retain certain data that is subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. This data is subject to governmental regulation at international, federal, state and local levels in many areas of our business, including data privacy and security laws such as the European Union (“EU”) and United Kingdom (“UK”) versions of the General Data Protection Regulation (“GDPR”), and the California Consumer Privacy Act, as amended by the California Privacy Rights Act (“CCPA”). To date, comprehensive state privacy laws have been proposed or passed in more than twenty U.S. states. We also operate in other jurisdictions (such as Mexico, Peru and Singapore) that have issued, or are considering the issuance of, data privacy laws and regulations. Additionally, the U.S. Federal Trade Commission and multiple state attorneys general are interpreting federal and state consumer protection laws to impose standards for the online collection, use, dissemination and security of data as well as requiring disclosures regarding such practices. Existing and potential future data privacy laws pose increasingly complex compliance, monitoring and control obligations and could potentially elevate our costs and risk exposure. As the implementation, interpretation, and enforcement of such laws continue to progress and evolve, there may also be developments that amplify such costs and risk exposure. Any failure by us, or by a third-party service provider upon which we rely, to comply with these laws and regulations, including as a result of a cybersecurity incident or privacy breach, could expose us to significant penalties and liabilities, including individual claims or consumer class actions, commercial litigation, administrative, and investigations or actions, regulatory intervention and sanctions or fines.
As we integrate artificial intelligence technologies into our processes, these technologies may present business, compliance and reputational risks.
Recent and continuously evolving technological advances in artificial intelligence (“AI”) and machine-learning technology present new opportunities and also pose new risks. Our integration of these technologies, whether developed internally or procured through our third-party service providers, into our processes may result in new or expanded risks and liabilities. Such risks and liabilities include enhanced governmental or regulatory scrutiny, litigation, compliance issues, ethical concerns, confidentiality or security risks, as well as other factors that could adversely affect our business, reputation, and financial results. The utilization of AI could also result in loss of intellectual property and subject us to heightened risks related to intellectual property infringement or misappropriation. The use of AI can lead to unintended consequences, including generating content that is inaccurate, misleading or otherwise flawed, or that results in unintended biases and discriminatory outcomes, which could harm our reputation and expose us to risks related to inaccuracies or errors in the output of such technologies.
The availability and cost of renewable identification numbers and credits related to low carbon fuel programs and incentives could have an adverse effect on our financial condition and results of operations.
Congress established a RFS program that requires annual volumes of renewable fuel be blended into domestic transportation fuel. As a producer of petroleum-based motor fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at least commensurate to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. Additionally, states, including California, have adopted or are considering adopting LCFS programs, which include the generation and purchase of LCFS credits for compliance. We are exposed to the volatility in the market price of RINs, LCFS credits, and other credits for low carbon fuels and we cannot predict the future prices of RINs, LCFS, or other credits. Prices are dependent upon a variety of factors, including the EPA, LCFS, and other regulations, reduction of the benefits, the availability of RINs or credits for purchase, whether any of the products we produce are deemed not to qualify for compliance, and levels of transportation fuels produced, which can vary significantly from quarter to quarter. There is currently no regulatory method for verifying the validity of most RINs sold on the open market. We have developed a RIN integrity program to vet the RINs that we purchase, and we incur costs to audit RIN generators. Nevertheless, if any of the RINs that we purchase and use for compliance are found to be invalid, we could incur costs and penalties for replacing the invalid RINs. See Item 1. Business – Regulatory Matters for additional information on these and other regulatory compliance matters.
Competitors that produce their own supply of feedstocks, own their own retail sites, or have greater financial resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined petroleum products. We compete with many companies for available supplies of crude oil and other feedstocks, and we do not produce any of our crude oil feedstocks. Our competitors include multinational, integrated major oil companies that can obtain a significant portion of their feedstocks from company-owned production. Competitors that produce crude oil are at times better positioned to withstand periods of depressed refining margins or feedstock shortages.
We also compete with other companies for customers for our refined petroleum products. The independent entrepreneurs who operate primarily Marathon-branded outlets and the direct dealer locations we supply compete with other convenience store chains, outlets owned or operated by integrated major oil companies or their dealers or jobbers, and other well-recognized national or regional retail outlets, often selling transportation fuels and merchandise at very competitive prices. Non-traditional
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transportation fuel retailers, such as supermarkets, club stores and mass merchants, may be betterable to withstand volatile market conditions or levels of low or no profitability in the retail segment of the market. The loss of market share by those who operate our branded outlets and the direct dealer locations we supply could adversely affect our business, financial condition, results of operations and cash flows.
We may be negatively impacted by inflation.
Increases in inflation may have an adverse effect on us. Such increases in inflation could impact the commodity markets generally, the overall demand for our products and services, our costs for labor, material and services and the margins we are able to realize on our products, all of which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation may also result in higher interest rates, which in turn would result in higher interest expense related to our variable rate indebtedness and any borrowings we undertake to refinance existing fixed rate indebtedness.
We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.
We utilize the services of third parties to transport crude oil and refined products to and from our refineries. In addition to our own operational risks, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines, railways or vessels to transport crude oil or refined products is disrupted or limited because of weather events, accidents, labor disputes, governmental regulations or third-party actions.
In particular, pipelines or railroads provide a nearly exclusive form of transportation of crude oil to, or refined products from, some of our refineries. A prolongedinterruption, material reduction or cessation of service of such a pipeline or railway, whether due to private party or governmental action or other reason, or any other prolongeddisruption of the ability of the trucks, pipelines, railways or vessels to transport crude oil or refined products to or from one or more of our refineries, can adversely affect us.
A significant decrease in oil and natural gas production in MPLX’s areas of operation may adversely affect MPLX’s business, financial condition, results of operations and cash available for distribution to its unitholders, including MPC.
A significant portion of MPLX’s operations is dependent on the continued availability of natural gas and crude oil production. The production from oil and natural gas reserves and wells owned by its producer customers will naturally decline over time, which means that MPLX’s cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of MPLX’s facilities, MPLX must continually obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful drilling activity near its facilities, its ability to compete for volumes from successful new wells and its ability to expand its system capacity as needed.
We have no control over the level of drilling activity in the areas of MPLX’s operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by demand, prevailing and projected energy prices, drilling costs, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Reductions or changes in exploration or production activity in MPLX’s areas of operations could lead to reduced throughput on its pipelines and utilization rates of its facilities.
Fluctuations in energy prices can negatively affect drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend upon factors beyond our control, including global and local demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, alternative energy sources such as wind, solar and other renewable energy technologies, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices could result in producers deciding to limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGLs to MPLX’s facilities and adversely affect their revenues and cash available for distribution to us.
This impact may also be exacerbated in circumstances where MPLX’s compensation for services is commodity-based, which are more directly impacted by changes in natural gas and NGL prices than its fee-based contracts due to frac spread exposure and may result in operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In addition, the purchase and resale of natural gas and NGLs in the ordinary course exposes MPLX to significant risk of volatility in natural gas or NGL prices due to the potential difference in price at the time of the purchases and then the subsequent sales. The significant volatility in natural gas, NGL and crude oil prices could adversely impact MPLX’s unit price, thereby increasing its distribution yield and cost of capital. Such impacts could adversely impact MPLX’s ability to execute its long‑term organic growth projects, satisfy obligations to its customers and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.
Severe weather events, other climate conditions and earth movement and other geological hazards may adversely affect our assets and ongoing operations.
Our assets are subject to acute physical risks, such as floods, hurricane-force winds, wildfires, winter storms, and earth movement in variable, steep and rugged terrain and terrain with varied or changing subsurface conditions, and chronic physical
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risks, such as sea-level rise or water shortages. The occurrence of these and similar events have had, and may in the future have, an adverse effect on our assets and operations. We have incurred and will continue to incur additional costs to protect our assets and operations from such physical risks and employ the evolving technologies and processes available to mitigate such risks. To the extent such severe weather events or other climate conditions increase in frequency and severity, we may be required to modify operations and incur costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.
We are subject to risks arising from our operations outside the United States and generally to worldwide political and economic developments.
We operate and sell some of our products and procure some feedstocks outside the United States. Our business, financial condition, results of operations and cash flows could be negatively impacted by disruptions in any of these markets, including economic instability, restrictions on the transfer of funds, supply chain disruptions, duties and tariffs, transportation delays, difficulty in enforcing contractual provisions, import and export controls, changes in governmental policies, political and social unrest, security issues involving key personnel and changing regulatory and political environments. Future outbreaks of infectious diseases or pandemics could affect demand for refined products and economic conditions generally. In addition, the deterioration of trade relationships, modification or termination of existing trade agreements, imposition of economic sanctions against Russia or other countries and the effects of potential responsive countermeasures, or increased taxes, border adjustments or tariffs can make international business operations more costly, which can have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are required to comply with U.S. and international laws and regulations, including those involving anti-bribery, anti-corruption and anti-money laundering. Our training and compliance program and our internal control policies and procedures may not always protect us from violations committed by our employees or agents. Actual or allegedviolations of these laws could disrupt our business and cause us to incur significant legal expenses and could result in a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.
More broadly, political and economic factors in global markets could impact crude oil and other feedstock supplies and could have a material adverse effect on us in other ways. Hostilities in the Middle East, Russia or elsewhere or the occurrence or threat of future terrorist attacks could adversely affect the economies of the U.S. and other countries. Lower levels of economic activity often result in a decline in energy consumption, which may cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for refined products, NGLs and natural gas. Additionally, these risks could increase instability in the financial and insurance markets and make it more difficult or costly for us to access capital and to obtain the insurance coverage that we consider adequate. Additionally, tax policy, legislative or regulatory action and commercial restrictions could reduce our operating profitability. For example, the U.S. government could prevent or restrict exports of refined products, NGLs, natural gas or the conduct of business in or with certain foreign countries. In addition, foreign countries could restrict imports, investments or commercial transactions or revoke or refuse to grant necessary permits.
Our investments in joint ventures could be adversely affected by our reliance on our joint venture partners and their financial condition, and our joint venture partners may have interests or goals that are inconsistent with ours.
We conduct some of our operations through joint ventures in which we share control over certain economic and business interests with our joint venture partners. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their obligations. Failure by us, or an entity in which we have an interest, to adequately manage the risks associated with any joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and adversely affect our reputation, business, financial condition, results of operations and cash flows.
Terrorist attacks or other targeted operational disruptions may affect our facilities or those of our customers and suppliers.
Refining, gathering and processing, pipeline and terminal infrastructure, and other energy assets, may be the subject of terrorist attacks or other targeted operational disruptions. Any attack or targeted disruption of our operations, those of our customers or, in some cases, those of other energy industry participants, could have a material and adverse effect on our business. Similarly, any similar event that severelydisrupts the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.
Financial Risks
We have significant debt obligations; therefore, our business, financial condition, results of operations and cash flows could be harmed by a deterioration of our credit profile or downgrade of our credit ratings, a decrease in debt capacity or unsecured commercial credit available to us, or by factors adversely affecting credit markets generally.
At December 31, 2025, our total debt obligations for borrowed money and finance lease obligations were $33.31 billion, including $26.01 billion of obligations of MPLX and its subsidiaries. We may incur substantial additional debt obligations in the future.
Our indebtedness may impose various restrictions and covenants on us that could have material adverse consequences, including:
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• increasing our vulnerability to changing economic, regulatory and industry conditions;
• limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our business and the industry;
• limiting our ability to pay dividends to our stockholders;
• limiting our ability to borrow additional funds; and
• requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing funds available for working capital, capital expenditures, acquisitions, share repurchases, dividends and other purposes.
A decrease in our debt or commercial credit capacity, including unsecured credit extended by third-party suppliers, or a deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit. Our credit rating is determined by independent credit rating agencies. We cannot provide assurance that any of our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any changes in our credit capacity or credit profile could materially and adversely affect our business, financial condition, results of operations and cash flows.
Significant variations in the market prices of crude oil and refined products can affect our financial performance.
Significant variations in the market prices of products held in our inventories could have a negative or positive effect on our financial performance. In addition, a sustained period of low crude oil prices may also result in significant financial constraints on certain producers from which we acquire our crude oil, which could result in long term crude oil supply constraints for our business. Such conditions could also result in an increased risk that our customers and other counterparties may be unable to fully fulfill their obligations in a timely manner, or at all.
A continued period of economic slowdown or recession, or a protracted period of depressed prices for crude oil or refined products, has significant and adverse consequences for our financial condition and the financial condition of our customers, suppliers and other counterparties, and diminishes our liquidity, and negatively affects our ability to obtain adequate crude oil volumes and to market certain of our products at favorable prices, or at all.
Our working capital, cash flows and liquidity can be significantly affected by decreases in commodity prices.
Payment terms for our crude oil purchases are generally longer than the terms we extend to our customers for refined product sales. As a result, the payables for our crude oil purchases are proportionally larger than the receivables for our refined product sales. Due to this net payables position, a decrease in commodity prices generally results in a use of working capital, and given the significant volume of crude oil that we purchase the impact can materially affect our working capital, cash flows and liquidity.
Increases in interest rates could adversely impact our ability to issue equity, refinance existing debt or incur additional debt for acquisitions or other purposes and our ability to pay dividends at our intended levels.
Our revolving credit facility has a variable interest rate. As a result, future interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future at or prior to the applicable stated maturity. A prolonged rising interest rate environment could have an adverse impact on our ability to issue equity, refinance existing debt or incur additional debt for acquisitions or other purposes on desirable terms, if at all. Accordingly, increases in interest rates could have a material adverse effect on our financial position, results of operations, cash flows and our ability to pay dividends at our intended levels.
We may incur losses and additional costs as a result of our forward-contract activities and derivative transactions.
We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we use to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. The risk of counterparty default is heightened in a poor economic environment. In addition, we may be required to incur additional costs in connection with future regulation of derivative instruments to the extent it is applicable to us.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards such as explosions, fires, refinery or pipeline releases, cybersecurity breaches or other incidents involving our assets or operations can reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.
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We have recorded goodwill and other intangible assets that could become further impaired and result in material non-cash charges to our results of operations.
We accounted for certain acquisitions using the acquisition method of accounting, which requires that the assets and liabilities of the acquired business be recorded to our balance sheet at their respective fair values as of the acquisition date. Any excess of the purchase consideration over the fair value of the acquired net assets is recognized as goodwill.
As of December 31, 2025, our balance sheet reflected $9.4 billion and $2.7 billion of goodwill and other intangible assets, respectively. We have in the past recorded significant impairments of our goodwill. To the extent the value of goodwill or intangible assets becomes further impaired, we may be required to incur additional material non-cash charges relating to such impairment. Our operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.
Large capital projects can be subject to delays, take years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.
Delays in completing capital projects or making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to market or supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
• denials of, delays in receiving, or revocations of requisite regulatory approvals or permits;
• unplanned increases in the cost of construction materials or labor, whether due to inflation or other factors;
• disruptions in transportation of components or construction materials;
• adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
• shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
• market-related increases in a project’s debt or equity financing costs;
• global supply chain disruptions;
• nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors; and
• delays due to citizen, state or local political or activist pressure.
Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our capital project returns and our business, financial condition, results of operations and cash flows.
Legal and Regulatory Risks
We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental and other laws or regulations. Changes to the federal government’s policies and operations could lead to increased regulatory uncertainty and volatility and increased state regulation, which may impact our business, financial condition and results of operations.
We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental and other laws or regulations. Changes to the federal government’s policies and operations could lead to increased regulatory uncertainty and volatility and increased state regulation, which may impact our business, financial condition and results of operations.
Our business is subject to numerous environmental laws and regulations at the federal, state and local level. These laws and regulations continue to increase in both number and complexity and affect our business. Laws and regulations expected to become more stringent relate to the following:
• the emission or discharge of materials into the environment;
• solid and hazardous waste management;
• the regulatory classification of materials currently or formerly used in our business;
• pollution prevention;
• climate change and GHG emissions;
• characteristics and composition of transportation fuels, including the blending of renewable fuels into transportation fuels;
• the production, importation, use, and disposal of specific chemicals;
• public and employee safety and health;
• permitting;
• inherently safer technology; and
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• facility security.
The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources, production processes and subsequent judicial interpretation of such laws and regulations. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations. We have incurred and may in the future incur liability for personal injury, property damage, natural resource damage or clean-up costs due to alleged contamination and/or exposure to chemicals such as benzene and methyl tert-butyl ether (“MTBE”). There is also increased regulatory interest in PFAS, which we expect will lead to increased monitoring and remediation obligations and potential liability related thereto. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.
In 2025, the U.S. presidential administration announced wide-ranging policy changes and issued numerous executive actions. The U.S. EPA and other federal agencies began proposing and promulgating regulations consistent with the administration’s policy changes. If the federal government relaxes or revokes certain environmental regulations, states may pass laws that vary in stringency and scope by state, creating a patchwork of regulation. For example, various states have passed laws regulating the use of materials containing PFAS and setting action levels for the remediation of certain PFAS. We cannot predict the extent to which states will pass such legislation, or the ultimate effect these state laws will have on our business, financial condition and results of operations.
The tax treatment of publicly traded partnerships or an investment in MPLX units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including MPLX, or an investment in MPLX common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, there are proposals to change the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate MPLX’s ability to qualify for partnership tax treatment.
We are unable to predict whether any such changes will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for MPLX to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships.
Climate change and GHG emission regulation could affect our operations, energy consumption patterns and regulatory obligations, any of which could adversely impact our business, results of operations and financial condition.
Currently, multiple legislative and regulatory measures to address GHG and other emissions are in various phases of consideration, promulgation or implementation. These include actions to develop international, federal, regional or statewide programs, which could require reductions in our GHG or other emissions, establish a carbon tax and decrease the demand for refined products. Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any emissions programs, including acquiring emission credits or allotments.
For example, California and Washington have enacted low carbon fuel standards. Other states are proposing, or have already promulgated, low carbon fuel standards or similar initiatives to reduce emissions from the transportation sector. If we are unable to pass the costs of compliance on to our customers, sufficient credits are unavailable for purchase, we have to pay a significantly higher price for credits, or if we are otherwise unable to meet our compliance obligation, our financial condition and results of operations could be adversely affected.
California has also enacted cap-and-invest programs, which set statewide limits on GHG emissions and caps that decline each year. CARB is currently developing regulations to implement the changes to the Cap-and-Invest program. We are unable to estimate the impact of these programs but requirements to drastically reduce GHG emissions in California could increase our operating costs, require additional capital expenditures, reduce the competitiveness of our California refinery and renewable fuel facility and our Washington refinery and affect their long term outlook.
Certain municipalities have also proposed or enacted restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect demand for the natural gas that MPLX transports and stores.
New York and Vermont have enacted, and other states are considering, laws that would allow the state to seek climate change-related damages from fossil fuel companies allocated based on each company’s share of past GHG emissions. The legality of these bills is being challenged in court. Our potential share is dependent on multiple factors, including the number of responsible parties and GHG emission calculation methodologies, and cannot be estimated at this time.
Regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and considerable uncertainty due to a number of factors including technological feasibility, legal challenges and potential changes in federal policy. Increasing concerns about climate change and carbon intensity have also resulted in societal concerns and a number of international and national measures to limit GHG emissions. Additional stricter measures and investor pressure can be expected in the future and any of these changes may have a material adverse impact on our business or financial condition.
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The scope and magnitude of the changes to U.S. climate change strategy under the current and future administrations, however, remain subject to the passage of legislation and interpretation and action of federal and state regulatory bodies; therefore, the impact to our industry and operations due to GHG regulation is unknown at this time.
Energy companies are subject to increasing environmental and climate-related litigation.
Governmental and other entities in various U.S. states have filed lawsuits against various energy companies, including us, allegingdamages as a result of climate change , false statements about climate change, and violations of various consumer protection statutes. The plaintiffs are seeking unspecified damages and abatement under various tort theories. Governments and private parties may continue to file lawsuits or initiate regulatory action based on allegations that certain public statements regarding climate change and other ESG related matters and practices by companies are false and misleading “greenwashing” that violatedeceptive trade practices and consumer protection statutes, presenting a high degree of uncertainty regarding the extent to which energy companies face an increased risk of liability stemming from climate change or ESG disclosures and practices.
Attorneys general and other government officials may continue to pursue litigation in which they seek to recover civil damagesagainst us on behalf of a state or its citizens for a variety of claims, including violation of consumer protection and product pricing laws or natural resources damages. Additionally, private plaintiffs and government parties have undertaken efforts to shut down energy assets by challenging operating permits, the validity of easements or the compliance with easement conditions. For example, the Dakota Access Pipeline, in which MPLX has a minority interest, is subject to, and may in the future be subject to, litigation seeking a permanent shutdown of the pipeline. There remains a high degree of uncertainty regarding the ultimate outcome of these types of proceedings, as well as their potential effect on our business, financial condition, results of operation and cash flows.
We are subject to risks associated with societal and political pressures and other forms of opposition to the development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and our ability to continue to operate or realize certain growth strategies.
We operate and develop our business with the expectation that regulations and societal sentiment will continue to enable the development, transportation and use of carbon-based fuels. However, policy decisions relating to the production, refining, transportation, storage and marketing of carbon-based fuels are subject to political pressures and the influence of public sentiment on GHG emissions, climate change, and climate adaptation. Additionally, societal sentiment regarding carbon-based fuels may adversely impact our reputation and ability to attract and retain employees.
The approval process for storage and transportation projects has become increasingly challenging, due in part to state and local concerns related to pipelines, negative public perception regarding the oil and gas industry, and concerns regarding GHG emissions downstream of pipeline operations. Our expansion or construction projects may not be completed on schedule (or at all), or at the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and the surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly.
Increasing attention to environmental, social and governance matters may impact our business and financial results.
In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community, including climate change, energy transition matters, and inclusion. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote ESG-related change at public companies, including, but not limited to, through the investment and voting practices of investment advisers, pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If this were to continue, it could have a material adverse effect on our access to capital. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHG emission reduction and energy transition strategies. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions, reduce GHG intensity for new and existing projects, increase our non-fossil fuel product portfolio, and/or address other ESG-related stakeholder concerns, our business and results of operations could be materially and adversely affected. Further, our reputation could be damaged as a result of our support of, association with or lack of support or disapproval of certain social causes, as well as any decisions we make to continue to conduct, or change, certain of our activities in response to such considerations.
Our goals, targets and disclosures related to ESG matters expose us to numerous risks, including risks to our reputation and stock price.
Companies across all industries are facing increasing scrutiny from stakeholders related to ESG matters, including practices and disclosures regarding climate-related initiatives. MPC has established a target to reduce Scope 1 and Scope 2 GHG emissions intensity and MPLX established a target to reduce methane emissions intensity. These targets reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. We assess progress with these targets on an annual basis. We may modify, discontinue, update or expand targets or adopt new metrics as new information, opportunities, and
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technologies become available. Further, there are conflicting expectations and priorities from regulatory authorities, investors, voluntary reporting frame works, and other stakeholders surrounding accounting and disclosure of ESG matters and climate related initiatives. Our efforts to accomplish and accurately report on these goals and objectives, which may be, in part, dependent on the actions of suppliers and other third parties, present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and stock price.
Efforts to achieve goals and targets, such as the foregoing and future internal climate-related initiatives, may increase costs, require purchase of carbon credits, or limit or impact our business plans and financial results, potentially resulting in the reduction to the economic end-of-life of certain assets and an impairment of the associated net book value, among other material adverse impacts. Additionally, as the nature, scope and complexity of ESG reporting, calculation methodologies, voluntary reporting standards and disclosure requirements expand, we may have to undertake additional costs to control, assess and report on ESG metrics. Our failure or perceived failure to pursue or fulfill such goals and targets or to satisfy various reporting standards within the timelines we announce, or at all, could have a negative impact on investor sentiment, ratings outcomes for evaluating our approach to ESG matters, stock price, and cost of capital and expose us to government enforcement actions and private litigation, among other material adverse impacts.
Regulatory and other requirements concerning the transportation of crude oil and other commodities by rail may cause increases in transportation costs or limit the amount of crude oil that we can transport by rail.
We rely on a variety of systems to transport crude oil, including rail. Rail transportation is regulated by federal, state and local authorities. New regulations or changes in existing regulations could result in increased compliance expenditures. Regulations that require the reduction of volatile or flammable constituents in crude oil that is transported by rail, change the design or standards for rail cars used to transport crude oil, change the routing or scheduling of trains carrying crude oil, or require any other changes that detrimentally affect the economics of delivering North American crude oil by rail could increase the time required to move crude oil to our refineries, increase the cost of rail transportation and decrease the efficiency of shipments of crude oil by rail. Any of these outcomes could have a material adverse effect on our business and results of operations.
If California or other jurisdictions (i) establish a maximum refining margin and impose a financial penalty for profits above such maximum refining margin, (ii) impose restrictions on turnaround and maintenance activities or (iii) require that petroleum refiners maintain a minimum inventory of transportation fuels , our financial results and profitability could be adversely affected.
In June 2023, the provisions of California’s Senate Bill No. 2 (such statute, together with any regulations contemplated or issued thereunder, “SB X1-2”) became effective, which, among other things, (i) authorized the establishment of a maximum gross gasoline refining margin and the imposition of a financial penalty for profits above a maximum gross gasoline refining margin, (ii) significantly expanded the reporting obligations to the California Energy Commission (“CEC”) for all participants in the petroleum industry supply chain in California, (iii) created the Division of Petroleum Market Oversight within the CEC to monitor and analyze the transportation fuels market, and (iv) authorized the CEC to regulate the timing and other aspects of refinery turnaround and maintenance activities in certain instances. The operational data reporting includes our plans for turnaround and maintenance activities at our Los Angeles refinery and Martinez renewable diesel facility and our plans to address potential impacts on feedstock and product inventories in California resulting from such turnaround and maintenance activities.
In late 2023, the CEC adopted (i) an order requiring an informational proceeding on a maximum gross gasoline refining margin and penalty under SB X1-2, and (ii) an order initiating rulemaking activity under SB X1-2 that will be focused on refinery maintenance and turnarounds. In August 2025, the CEC adopted resolutions (i) indicating that the CEC will not take further action on a maximum gross gasoline refining margin and penalty for at least five years and (ii) providing refiners with a potential exemption from a maximum gross gasoline refining margin, if a maximum gross gasoline refining margin is implemented prior to the year 2035.
In October 2024, California’s governor signed Assembly Bill No.1 (such statute, together with any regulations contemplated or issued thereunder, “AB X2-1”) into law, authorizing the CEC to require that petroleum refiners maintain a minimum inventory of transportation fuels including the requirement that petroleum refiners plan for resupply during scheduled maintenance. In August 2025, the CEC adopted an order requiring an informational proceeding on minimum inventory requirements and refinery maintenance resupply planning requirements.
To the extent that the CEC establishes a maximum gross gasoline refining margin and imposes a financial penalty for profits above such maximum gross gasoline refining margin or requires that petroleum refiners maintain a minimum inventory of transportation fuels, our financial results and profitability could be adversely affected. Our results of operations, financial performance and safety and maintenance efforts could also be adversely impacted to the extent that restrictions on turnaround and maintenance activities are imposed by the CEC. We cannot reasonably predict the impact that full implementation of SB X1-2 or AB X2-1 will have on our California operations nor can we predict the impact from similarly focused legislation or actions in other jurisdictions in which we operate. The recently adopted legislation in California, and the future enactment of similar legislation in any of the other jurisdictions, could adversely impact our business, financial condition, results of operations and cash flows.
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Increased regulation of hydraulic fracturing and other oil and gas production activities could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely affect our results of operations and financial condition.
While we do not conduct hydraulic fracturing operations, we do provide gathering, treating, processing and fractionation services with respect to natural gas and NGLs produced by our customers as a result of such operations. A range of federal, state and local laws and regulations currently govern or, in some cases, prohibit hydraulic fracturing in some jurisdictions. Stricter laws, regulations and permitting processes may be enacted in the future. If federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing or other oil and gas production activities are enacted or expanded, such efforts could impede oil and gas production, increase producers’ cost of compliance, and result in reduced volumes available for our midstream assets to gather, treat, process and fractionate.
Historic or current operations could subject us to significant legal liability or restrict our ability to operate.
We currently are defendinglitigation and anticipate we will be required to defend new litigation in the future. Our operations, including those of MPLX, and those of our predecessors could expose us to litigation for allegeddamages related to contamination of the environment or personal injuries caused by releases of hazardous substances from our facilities, products liability, consumer credit or privacy laws, product pricing or antitrust laws or any other laws or regulations that apply to our operations. While an adverse outcome in most litigation matters would not be expected to be material to us, in class-action litigation, large classes of plaintiffs may allegedamages relating to extended periods of time or other alleged facts and circumstances that could increase the amount of potential damages. Attorneys general and other government officials have in the past and may in the future pursue litigation in which they seek to recover civil damages from companies on behalf of a state or its citizens for a variety of claims, including violation of consumer protection and product pricing laws or natural resources damages. If we are not able to successfullydefend such litigation, it may result in liability to our company that could materially and adversely affect our business, financial condition, results of operations and cash flows. In addition to substantial liability, plaintiffs in litigation may also seek injunctive relief which, if imposed, could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
A portion of our workforce is unionized, and we may face labor disruptions that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Approximately 3,800 of our employees are covered by collective bargaining agreements with expiration dates ranging from 2027 to 2031. Approximately 700 of those hourly represented employees in California are covered by collective bargaining agreements that were set to expire on January 31, 2026. The parties agreed to continue those agreements beyond expiration, subject to a 24-hour termination notice by either party, while successor agreements are negotiated and ratified. These agreements may be renewed at an increased cost to us. In addition, we have experienced in the past, and may experience in the future, work stoppages as a result of labor disagreements. Any prolonged work stoppagesdisrupting operations could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, some states in which we operate require refinery owners to pay prevailing wages to contract craft workers and restrict refiners’ ability to hire qualified employees to a limited pool of applicants. Legislation or changes in regulations could result in labor shortages, higher labor costs, and an increased risk that contract workers become joint employees, which could trigger bargaining issues, and wage and benefit consequences, especially during critical maintenance and construction periods.
One of our subsidiaries acts as the general partner of a master limited partnership, which may expose us to certain legal liabilities.
One of our subsidiaries acts as the general partner of MPLX, a master limited partnership. Our control of the general partner of MPLX may increase the possibility of claims of breach of fiduciary duties, including claims of conflicts of interest. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
If foreign investment in us or MPLX exceeds certain levels, we could be prohibited from operating vessels engaged in U.S. coastwise trade, which could adversely affect our business, financial condition, results of operations and cash flows.
The Shipping Act of 1916 and Merchant Marine Act of 1920 (together, the “Maritime Laws”) generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters or otherwise in U.S. coastwise trade. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.
Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our business.
We do not own all of the land on which certain of our assets are located, particularly our midstream assets, but rather obtain the rights to construct and operate such assets on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the possibility of more burdensome terms and increased costs to retain necessary land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined that we do not have valid leases, rights-of-way or other property rights. For example, a portion of the Tesoro High Plains Pipeline in North Dakota remains
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shut down following delays in renewing a right-of-way necessary for the operation of a section of the pipeline. Any loss of or reduction in our real property rights, including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way agreements or permits on satisfactory terms or at all, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which can increase our costs and delay or prevent our efforts to conduct operations.
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal lands. One or more of these factors has in the past and may in the future increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct operations on such lands. For example, we are subject to ongoing litigation regarding trespass claims relating to a portion of the Tesoro High Plains Pipeline in North Dakota.
The Court of Chancery of the State of Delaware will be, to the extent permitted by law, the sole and exclusive forum for most disputes between us and our shareholders.
Our Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have subject matter jurisdiction, the federal district court for the District of Delaware) will be the sole and exclusive forum for:
• any derivative action or proceeding brought on behalf of MPC;
• any action asserting a claim of breach of a fiduciary duty owed by any director or officer of MPC to MPC or its stockholders;
• any action asserting a claim against MPC arising pursuant to any provision of the General Corporation Law of the State of Delaware, MPC’s Restated Certificate of Incorporation, any Preferred Stock Designation or the Bylaws of MPC; or
• any other action asserting a claim against MPC or any Director or officer of MPC that is governed by or subject to the internal affairs doctrine for choice of law purposes.
The exclusive forum provision does not apply to suits brought to enforce any liability or duty created by the Securities Exchange Act of 1934 (the “Exchange Act”) or any other claim for which the federal courts have exclusive jurisdiction. Our Restated Certificate of Incorporation also provides that, unless we consent in writing to the selection of an alternative forum, the U.S. federal district courts shall be, to the fullest extent permitted by law, the exclusive forum for any action asserting a claim under the Securities Act.
The forum selection provision may restrict a stockholder’s ability to bring a claim against us or directors or officers of MPC in a forum that it finds favorable, which may discourage stockholders from bringing such claims at all. Alternatively, if a court were to find the forum selection provision contained in our Restated Certificate of Incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in another forum, which could materially adversely affect our business, financial condition and results of operations.
Provisions in our corporate governance documents could operate to delay or prevent a change in control of our company, dilute the voting power or reduce the value of our capital stock or affect its liquidity.
The existence of some provisions within our restated certificate of incorporation and amended and restated bylaws could discourage, delay or prevent a change in control of us that a stockholder may consider favorable. These include provisions:
• providing that our board of directors fixes the number of members of the board;
• providing for the division of our board of directors into three classes with staggered terms;
• providing that only our board of directors may fill board vacancies;
• limiting who may call special meetings of stockholders;
• prohibiting stockholder action by written consent, thereby requiring stockholder action to be taken at a meeting of the stockholders;
• establishing advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted on by stockholders at stockholder meetings;
• establishing supermajority vote requirements for certain amendments to our restated certificate of incorporation;
• providing that our directors may only be removed for cause;
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• authorizing a large number of shares of common stock that are not yet issued, which would allow our board of directors to issue shares to persons friendly to current management, thereby protecting the continuity of our management, or which could be used to dilute the stock ownership of persons seeking to obtain control of us; and
• authorizing the issuance of “blank check” preferred stock, which could be issued by our board of directors to increase the number of outstanding shares and thwart a takeover attempt.
Our restated certificate of incorporation also authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock respecting dividends and distributions, as our board of directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant holders of preferred stock the right to elect some number of our board of directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.
Finally, to facilitate compliance with the Maritime Laws, our restated certificate of incorporation limits the aggregate percentage ownership by non-U.S. citizens of our common stock or any other class of our capital stock to 23 percent of the outstanding shares. We may prohibit transfers that would cause ownership of our common stock or any other class of our capital stock by non-U.S. citizens to exceed 23 percent. Our restated certificate of incorporation also authorizes us to effect any and all measures necessary or desirable to monitor and limit foreign ownership of our common stock or any other class of our capital stock. These limitations could have an adverse impact on the liquidity of the market for our common stock if holders are unable to transfer shares to non-U.S. citizens due to the limitations on ownership by non-U.S. citizens. Any such limitation on the liquidity of the market for our common stock could adversely impact the market price of our common stock.
General Risk Factors
Significant stockholders may attempt to effect changes at our company or acquire control over our company, which could impact the pursuit of business strategies and adversely affect our results of operations and financial condition.
Our stockholders may from time to time engage in proxy solicitations, advance stockholder proposals or otherwise attempt to effect changes or acquire control over our company. Campaigns by stockholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term stockholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist stockholders can be costly and time-consuming and could divert the attention of our board of directors and senior management from the management of our operations and the pursuit of our business strategies. As a result, stockholder campaigns could adversely affect our results of operations and financial condition.
Significant acquisitions, including the Northwind Midstream Acquisition and the BANGL Acquisition, will involve the integration of new assets or businesses and may present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.
Significant acquisitions, including the Northwind Midstream Acquisition and the BANGL Acquisition, involving the addition of new assets or businesses will present risks, which may include, among others:
• inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
• an inability to successfully integrate, or a delay in the successful integration of, assets or businesses we acquire;
• a decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;
• a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;
• the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
• the diversion of management’s attention from other business concerns;
• the loss of customers or key employees from the acquired business; and
• the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
Compliance with and changes in tax laws could materially and adversely impact our financial condition, results of operations and cash flows.
We are subject to extensive tax liabilities, including federal, state and local income taxes in the United States and in foreign jurisdictions, and, transactional, payroll, franchise, withholding and property taxes. New tax laws and regulations and changes in, interpretations of, and guidance regarding tax laws and regulations, including impacts of the Tax Cuts and Jobs Act of 2017, the Coronavirus Aid, Relief, Economic Security Act of 2020, the Inflation Reduction Act of 2022, and the One Big Beautiful Bill Act of 2025, could result in increased expenditures by us for tax liabilities in the future and could materially and adversely impact our financial condition, results of operations and cash flows.
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In addition, we are subject to the examination of our returns by taxing authorities. We regularly assess the likelihood of adverse outcomes resulting from such examinations to determine the adequacy of our provision for income taxes. Although we believe we have made appropriate provisions for taxes in the jurisdictions in which we operate, changes in the tax laws or challenges from tax authorities under existing tax laws could adversely affect our business, financial condition and results of operations and could subject us to interest and penalties.
strong
benefitting
opportunities
In response to the current business environment, we continue to focus on the following priorities for our business:
Commitment to Safety, Reliability and Sustainability
We remain steadfast in our commitment to safely and reliably operate our assets and protect the health and safety of our employees. We are focused on sustainable structural changes to improve our cost competitiveness while maintaining safe and reliable operations. Our approach to sustainability spans the environmental, social and governance dimensions of our business. That means strengthening resiliency by lowering the carbon intensity and conserving natural resources; innovating for the future by investing in renewables and emerging technologies; and embedding sustainability in decision-making and in how we engage our people and many stakeholders. We have existing targets for reducing Scope 1 & 2 GHG emissions intensity, for lowering methane emissions intensity and for lowering our freshwater withdrawal intensity.
Operational Excellence
We are committed to achieving operational excellence by reducing costs, improvingefficiency, driving operational improvements and being disciplined in capital allocation. This means lowering our costs in all aspects of our business and challenging ourselves to be disciplined in every dollar we spend across our organization. We look to optimize our portfolio of investment opportunities to ensure efficient deployment of capital focusing on projects with the highest returns.
Commercial Performance
We are focused on leveraging the complexity of our facilities by selecting advantaged raw materials, new approaches in the commercial space to be more dynamic amidst changing market conditions and achieving technological improvements to advance our commercial performance.
Integrated Value Chain Optimization
We are committed to leveraging our value chain so that we are a leader in operational, financial, and sustainability performance. Our goal is to improve value chain optimization with a more integrated and advanced approach to decision making so that each individual asset generates free cash flow back to the business and contributes to shareholder returns. With our investments, we are focused on high returning projects that we believe will enhance the competitiveness of our portfolio, including our investments in sustainable fuels and technologies that lower our carbon intensity as the global energy mix evolves.
Strategic Updates
Midstream Transactions
Divestiture of Rockies Operations
On November 12, 2025, MPLX completed the sale of its Rockies gathering and processing assets (the “Rockies”) to a subsidiary of Harvest Midstream (“Harvest”) for $980 million in cash. The transaction resulted in a gain of $159 million.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the sale of the Rockies.
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Northwind Midstream Acquisition
On August 29, 2025, MPLX completed the acquisition of 100 percent of Northwind Midstream for $2.4 billion in cash. Northwind Midstream provides sour gas gathering and treating services in Lea County, New Mexico, which enhances MPLX’s Permian natural gas and NGL value chain. The Northwind Midstream Acquisition was accounted for as a business combination. The Northwind Midstream Acquisition and incremental capital expenditures associated with in-process expansion projects, were financed with a portion of the net proceeds from MPLX's $4.5 billion senior notes issuance in August 2025.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the Northwind Midstream Acquisition.
BANGL, LLC Acquisition
On July 1, 2025, MPLX purchased the remaining 55 percent interest in BANGL, LLC (“BANGL”) for $703 million cash, plus an earnout provision of up to $275 million based on targeted EBITDA growth from 2026 to 2029. As a result of the BANGL Acquisition, MPLX now owns 100 percent of BANGL and its results are reflected in our Midstream segment within our consolidated financial results. The BANGL Acquisition was accounted for as a business combination, resulting in the recognition of a $484 million gain.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the BANGL Acquisition.
Whiptail Midstream Acquisition
On March 11, 2025, MPLX acquired gathering businesses from Whiptail Midstream, LLC for $235 million in cash (the “Whiptail Midstream Acquisition”). These San Juan basin assets consist primarily of crude and natural gas gathering systems in the Four Corners region. The acquisition was accounted for as a business combination.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the Whiptail Midstream Acquisition.
Sale of Interest in Ethanol Joint Venture
On July 31, 2025, MPC sold its 49.9 percent interest in The Andersons Marathon Holdings LLC (“TAMH”) to The Andersons Ethanol LLC (the “Ethanol Joint Venture Sale”) in exchange for cash proceeds of $427 million. MPC’s investment in TAMH was accounted for as an equity method investment and previously reported in the Refining & Marketing segment. Upon closing, MPC derecognized the carrying value of the equity method investment of $173 million and recorded a gain of $254 million.
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Results
Our chief operating decision maker (“CODM”) evaluates the performance of our segments using segment adjusted EBITDA. Amounts included in income before income taxes and excluded from segment adjusted EBITDA include: (i) depreciation and amortization; (ii) net interest and other financial costs; (iii) turnaround expenses; and (iv) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
Select results for continuing operations for 2025 and 2024 are reflected in the following table.
(Millions of dollars)
Segment adjusted EBITDA for reportable segments
Refining & Marketing
Midstream
Renewable Diesel
Total reportable segments
Reconciliation of segment adjusted EBITDA for reportable segments to income before income taxes
Renewable Diesel JV depreciation and amortization (a)
Net interest and other financial costs
Income before income taxes
Net Income attributable to MPC per diluted share
(a) Represents MPC’s pro-rata share of expenses from joint ventures included within the Renewable Diesel segment.
(b) 2025 includes gains from the BANGL Acquisition, the Ethanol Joint Venture Sale and the Rockies divestiture. 2024 includes the gain resulting from MPLX and its joint venture partner contributing their respective membership interests in Whistler Pipeline, LLC to a newly formed joint venture, WPC Parent, LLC, and issuing a 19 percent voting interest in WPC Parent, LLC to an affiliate of Enbridge Inc. in exchange for the contribution of cash and the Rio Bravo Pipeline project (collectively the “Whistler Joint Venture Transaction”). See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on these transactions.
(c) Transaction-related costs include costs associated with the Northwind Midstream Acquisition, the BANGL Acquisition and the Rockies divestiture discussed in Item 8. Financial Statements and Supplementary Data - Note 5 .
Net income attributable to MPC increased $602 million, or $3.14 per diluted share, in 2025 compared to 2024. Refer to the Results of Operations section for a discussion of financial results by segment for the three years ended December 31, 2025.
MPLX
We received limited partner distributions of $2.56 billion and $2.27 billion from MPLX during 2025 and 2024, respectively. We owned approximately 647 million MPLX common units at December 31, 2025 with a market value of $34.55 billion based on the December 31, 2025 closing unit price of $53.37. On January 29, 2026, MPLX declared a quarterly cash distribution of $1.0765 per common unit, which was paid February 17, 2026. As a result, MPLX made distributions totaling $1.09 billion to its common unitholders for the fourth quarter of 2025. MPC’s portion of these distributions was approximately $697 million.
During the year ended December 31, 2025, MPLX repurchased approximately 8 million MPLX common units at an average cost per unit of $51.58 and paid approximately $400 million of cash. As of December 31, 2025, $1.12 billion remained available under the authorizations for future repurchases.
See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.
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OVERVIEW OF SEGMENTS
Refining & Marketing
Refining & Marketing segment adjusted EBITDA depends largely on our refinery throughputs, Refining & Marketing margin, refining operating costs and distribution costs. Our total refining capacity was 2,986 mbpcd, 2,963 mbpcd and 2,950 mbpcd as of December 31, 2025, 2024 and 2023, respectively.
Refining & Marketing margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries and the costs of products purchased for resale. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Gulf Coast, Mid-Continent and West Coast crack spreads that we believe most closely track our operations and slate of products. The following are used for these crack-spread calculations:
• The Gulf Coast crack spread uses three barrels of MEH crude producing two barrels of USGC CBOB gasoline and one barrel of USGC ULSD;
• The Mid-Continent crack spread uses three barrels of WTI crude producing two barrels of Chicago CBOB gasoline and one barrel of Chicago ULSD; and
• The West Coast crack spread uses three barrels of ANS crude producing two barrels of LA CARBOB and one barrel of LA CARB Diesel.
Our refineries can process a variety of sweet and sour crude oil, which typically can be purchased at a discount to crude oil referenced in our Gulf Coast, Mid-Continent and West Coast crack spreads. The amount of these discounts, which we refer to as the sweet differential and the sour differential, can vary significantly, causing our Refining & Marketing margin to differ from blended crack spreads. In general, larger sweet and sour differentials will enhance our Refining & Marketing margin.
Future crude oil differentials will be dependent on a variety of market and economic factors, as well as U.S. energy policy.
The following table provides sensitivities showing an estimated change in annual Refining & Marketing segment adjusted EBITDA due to potential changes in market conditions.
Natural gas price sensitivity (d) (per $1.00/MMBtu)
(a) Crack spread based on 42 percent MEH, 40 percent WTI and 18 percent ANS with Gulf Coast, Mid-Continent and West Coast product pricing, respectively, and assumes all other differentials and pricing relationships remain unchanged.
(b) Sour crude oil basket consists of the following crudes: ANS, Argus Sour Crude Index, Maya and Western Canadian Select. We assume approximately 50 percent of the crude processed at our refineries in 2026 will be sour crude.
(c) Sweet crude oil basket consists of the following crudes: Bakken, Brent, MEH, WTI-Cushing and WTI-Midland. We assume approximately 50 percent of the crude processed at our refineries in 2026 will be sweet crude.
(d) This is consumption-based exposure for our Refining & Marketing segment and does not include the sales exposure for our Midstream segment.
In addition to the market changes indicated by the crack spreads, the sour differential and the sweet differential, our Refining & Marketing margin is impacted by factors such as:
• the selling prices realized for refined products;
• the types of crude oil and other charge and blendstocks processed;
• our refinery yields;
• the cost of products purchased for resale;
• the impact of commodity derivative instruments used to hedge price risk;
• the potential impact of lower of cost or market adjustments to inventories in periods of declining prices;
• the potential impact of LIFO adjustments; and
• the cost of purchasing RINs in the open market to comply with RFS requirements.
Inventories are stated at the lower of cost or market. Costs of crude oil, refinery feedstocks and refined products are stated under the LIFO inventory costing method and aggregated on a consolidated basis for purposes of assessing if the cost basis of these inventories may have to be written down to market values. At December 31, 2025, market values for refined products exceed
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their cost basis and, therefore, there is no lower of cost or market inventory valuation reserve at the end of the year. Based on movements of refined product prices, future inventory valuation adjustments could have a negative effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover.
Refining & Marketing segment adjusted EBITDA is also affected by changes in refining operating costs in addition to committed distribution costs. Changes in operating costs are primarily driven by the cost of energy used by our refineries, including purchased natural gas, and the level of maintenance costs. Distribution costs primarily include long-term agreements with MPLX, which as discussed below include minimum commitments to MPLX, and will negatively impact segment adjusted EBITDA in periods when throughput or sales are lower or refineries are idled.
We have various long-term, fee-based commercial agreements with MPLX. Under these agreements, MPLX, which is reported in our Midstream segment, provides transportation, storage, distribution and marketing services to our Refining & Marketing segment. Certain of these agreements include commitments for minimum quarterly throughput and distribution volumes of crude oil and refined products and minimum storage volumes of crude oil, refined products and other products. Certain other agreements include commitments to pay for 100 percent of available capacity for certain marine transportation and refining logistics assets.
Midstream
Our Midstream segment gathers, transports, stores and distributes crude oil, refined products, including renewable diesel, and other hydrocarbon-based products, principally for our Refining & Marketing segment. Additionally, the segment markets refined products. The profitability of our pipeline transportation operations primarily depends on tariff rates and the volumes shipped through the pipelines. The profitability of our marine operations primarily depends on the quantity and availability of our vessels and barges. The profitability of our light product terminal operations primarily depends on the throughput volumes at these terminals. The profitability of our fuels distribution services primarily depends on the sales volumes of certain refined products. The profitability of our refining logistics operations depends on the quantity and availability of our refining logistics assets. A majority of the crude oil and refined product shipments on our pipelines and marine vessels and the refined product throughput at our terminals serve our Refining & Marketing segment and our refining logistics assets and fuels distribution services are used solely by our Refining & Marketing segment. As discussed above in the Refining & Marketing section, MPLX, which is reported in our Midstream segment, has various long-term, fee-based commercial agreements related to services provided to our Refining & Marketing segment. Under these agreements, MPLX has received various commitments of minimum throughput, storage and distribution volumes as well as commitments to pay for all available capacity of certain assets. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines, terminals and marine operations. Key factors in this supply and demand balance are the production levels of crude oil by producers in various regions or fields, the availability and cost of alternative modes of transportation, the volumes of crude oil processed at refineries and refinery and transportation system maintenance levels. The volume of refined products that we transport, store, distribute and market is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines and marine operations. In most of our markets, demand for gasoline and distillate peaks during the summer driving season, which extends from May through September of each year, and declines during the fall and winter months. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.
Our Midstream segment also gathers, treats, processes and transports natural gas and transports, fractionates, stores and markets NGLs. NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our Midstream segment profitability is affected by prevailing commodity prices primarily as a result of processing or conditioning at our own or third‑party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index‑related prices and the cost of third‑party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by our producer customers, such prices also affect profitability.
Renewable Diesel
Our Renewable Diesel segment processes renewable feedstocks into renewable diesel, markets and distributes renewable diesel and includes joint ventures that produce soybean oil and renewable diesel.
Inventories are stated at the lower of cost or market. Costs of renewable feedstocks and renewable diesel are stated under the LIFO inventory costing method and aggregated on a consolidated basis, including traditional and renewable products, for purposes of assessing if the cost basis of these inventories may have to be written down to market values. At December 31, 2025, market values for all refined product inventories exceed their cost basis and, therefore, there is no lower of cost or market inventory valuation reserve at the end of the year. Based on movements of renewable product prices, future inventory valuation adjustments could have a negative effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover.
Our Renewable Diesel segment adjusted EBITDA is also affected by changes in operating costs, distribution costs, throughput and certain regulatory credits.
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RESULTS OF OPERATIONS
The following discussion includes comments and analysis relating to our results of operations for the years ended December 31, 2025, 2024 and 2023. This discussion should be read in conjunction with Item 8. Financial Statements and Supplementary Data and is intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.
Consolidated Results of Operations
(Millions of dollars)
2025 vs. 2024 Variance
2024 vs. 2023 Variance
Revenues and other income:
Sales and other operating revenues
Income from equity method investments
Net gain on disposal of assets
Other income
Total revenues and other income
Costs and expenses:
Cost of revenues (excludes items below)
Depreciation and amortization
Selling, general and administrative expenses
Other taxes
Total costs and expenses
Income from continuing operations
Net interest and other financial costs
Income before income taxes
Provision for income taxes
Net income
Less net income attributable to:
Redeemable noncontrolling interest
Noncontrolling interests
Net income attributable to MPC
2025 Compared to 2024
Net income attributable to MPC increased $602 million in 2025 compared to 2024, due to the following:
Total revenues and other income decreased $5.19 billion in 2025 compared to 2024 primarily due to:
• decreased sales and other operating revenues of $6.17 billion primarily due to a decrease in average refined product sales prices of $0.18 per gallon, or 8 percent, partially offset by increased refined product sales volumes of 133 mbpd, or 4 percent;
• increased income from equity method investments of $574 million largely due to gains from the BANGL Acquisition of $484 million and the Ethanol Joint Venture Sale of $254 million, partially offset by the absence of the gain on sale of assets of $151 million resulting from the Whistler Joint Venture Transaction in 2024;
• increased net gain on disposal of assets of $145 million mainly due to the $159 million gain on the divestiture of the Rockies operations; and
• increased other income of $256 million largely due to legal settlements of $253 million and higher income on RINs sales, partially offset by lower insurance proceeds.
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Total costs and expenses decreased $6.69 billion in 2025 compared to 2024 primarily due to:
• decreased cost of revenues of $6.79 billion primarily due to lower crude oil costs;
• decreased depreciation and amortization of $86 million largely due to major refining assets that were fully depreciated at the end of 2024, partially offset by depreciation from recent acquisitions;
• increased selling, general and administrative expenses of $128 million primarily due to increases in salaries and employee related expenses of $88 million, contract services costs of $39 million and insurance expenses of $24 million, partially offset by the absence of $30 million of expense in 2024 related to decommissioning of non-operating assets; and
• increased other taxes of $67 million largely due to the absence of a property tax appeal settlement of $49 million received in 2024 related to retroactive tax assessments for prior periods.
Net interest and other financial costs increased $437 million largely due to decreased interest income and discount amortization, primarily due to the liquidation of short-term investments that were held in 2024, and increased interest expense, largely due to increased MPLX borrowings, and non-service pension costs. We capitalized interest of $100 million in 2025 and $57 million in 2024. See Item 8. Financial Statements and Supplementary Data – Note 11 for further details.
We recorded combined federal, state and foreign income tax provisions of $1.14 billion and $890 million for the years ended December 31, 2025 and 2024, respectively, which were lower than the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.
Net income attributable to noncontrolling interests increased $236 million mainly due to an increase in MPLX’s net income.
2024 Compared to 2023
Net income attributable to MPC decreased $6.24 billion in 2024 compared to 2023, due to the following:
Total revenues and other income decreased $9.90 billion in 2024 compared to 2023 primarily due to:
• decreased sales and other operating revenues of $9.52 billion primarily due to decreased average refined product sales prices of $0.24 per gallon, or 10 percent, partially offset by increased refined product sales volumes of 75 mbpd, or 2 percent;
• increased income from equity method investments of $306 million largely due to the gain on the sale of assets resulting from the Whistler Joint Venture Transaction and increased income from our Martinez Renewables joint venture;
• decreased net gain on disposal of assets of $189 million mainly due to the $106 million gain on the sale of MPC’s 25 percent interest in South Texas Gateway and $92 million associated with the remeasurement of MPLX’s existing equity investment in MarkWest Torñado GP, L.L.C. (“Torñado”), arising from the acquisition of the remaining 40 percent interest in 2023; and
• decreased other income of $497 million largely due to lower income on RINs sales and lower insurance proceeds.
Total costs and expenses decreased $2.18 billion in 2024 compared to 2023 primarily due to:
• decreased cost of revenues of $2.33 billion primarily due to lower crude oil costs and finished product purchases, partially offset by higher contract services and material and supply expenses related to increased turnaround activity;
• increased selling, general and administrative expenses of $182 million primarily due to increased contract services costs of $96 million, office and rent expenses of $31 million and $30 million of expense related to decommissioning of non-operating assets; and
• decreased other taxes of $63 million largely due to a property tax appeal settlement of $49 million related to retroactive tax assessments for prior periods.
Net interest and other financial costs increased $314 million largely due to decreased interest income of $154 million, primarily on short-term investments, increased pension non-service costs of $52 million and increased interest expense of $41 million due to higher MPLX borrowings. We capitalized interest of $57 million in 2024 and $60 million in 2023. See Item 8. Financial Statements and Supplementary Data – Note 11 for further details.
We recorded a combined federal, state and foreign income tax provision of $890 million for the year ended December 31, 2024, which was lower than the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests. We recorded a combined federal, state and foreign income tax provision of $2.82 billion for the year ended December 31, 2023, which was lower than the tax computed at the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests, partially offset by state taxes. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.
Net income attributable to noncontrolling interests increased $198 million mainly due to an increase in MPLX’s net income.
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Segment Results
We classify our business in the following reportable segments: Refining & Marketing, Midstream and Renewable Diesel. Segment adjusted EBITDA represents adjusted EBITDA attributable to the reportable segments. Amounts included in income before income taxes and excluded from segment adjusted EBITDA include: (i) depreciation and amortization; (ii) net interest and other financial costs; (iii) turnaround expenses and (iv) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
Our segment adjusted EBITDA for reportable segments was approximately $12.78 billion, $12.10 billion and $19.81 billion for the years ended December 31, 2025, 2024 and 2023, respectively.
Refining & Marketing
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) Includes intersegment sales to the Midstream segment and sales destined for export.
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Refining & Marketing Operating Statistics
Net refinery throughput (mbpd )
Refining & Marketing margin per barrel (a)(b)
Less:
Refining operating costs per barrel (c)
Distribution costs per barrel (d)
LIFO inventory adjustment
Other per barrel (e)
Refining & Marketing adjusted EBITDA per barrel
Refining planned turnaround costs per barrel
Depreciation and amortization per barrel
Per barrel fees paid to MPLX included in distribution costs above
(a) Sales revenue less cost of refinery inputs and purchased products, divided by net refinery throughput.
(b) See “Non-GAAP Measures” section for reconciliation and further information regarding this non-GAAP measure.
(c) Refining operating costs exclude planned turnaround and depreciation and amortization expense.
(d) Distribution costs exclude depreciation and amortization expense.
(e) Includes income (loss) from equity method investments, net gain (loss) on disposal of assets and other income.
The following table presents certain benchmark prices in our marketing areas and market indicators that we believe are helpful in understanding the results of our Refining & Marketing segment. The benchmark crack spreads below do not reflect the market cost of RINs necessary to meet the EPA renewable volume obligations for attributable products under the Renewable Fuel Standard.
Benchmark spot prices (dollars per gallon)
Chicago CBOB unleaded regular gasoline
Chicago ultra-low sulfur diesel
USGC CBOB unleaded regular gasoline
USGC ultra-low sulfur diesel
LA CARBOB
LA CARB diesel
Market Indicators (dollars per barrel)
WTI
MEH
ANS
Crack Spreads
Mid-Continent WTI 3-2-1
USGC MEH 3-2-1
West Coast ANS 3-2-1
Blended 3-2-1 (a)
Crude Oil Differentials
Sweet
Sour
(a) Beginning in the second quarter of 2024, the blended crack spreads are weighted 42 percent of the USGC crack spread, 40 percent of the Mid-Continent crack spread and 18 percent of the West Coast crack spread. The blended crack spreads for prior periods were weighted 40 percent of the USGC crack spread, 40 percent of the Mid-Continent crack spread and 20 percent of the West Coast crack spread. These blends are based on MPC’s refining capacity by region in each period.
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2025 Compared to 2024
Refining & Marketing segment revenues decreased $7.45 billion primarily due to a decrease in average refined product sales prices of $0.18 per gallon, partially offset by increased refined product sales volumes of 133 mbpd.
Refinery crude oil capacity utilization was 94 percent during 2025 and net refinery throughput increased 67 mbpd in 2025.
Refining & Marketing segment adjusted EBITDA increased $435 million primarily driven by increased per barrel margins and increased refined product sales volumes.
Refining & Marketing margin was $16.87 per barrel for 2025 compared to $16.01 per barrel for 2024. Refining & Marketing margin is affected by the market indicators shown earlier, which use spot market values and an estimated mix of crude purchases and product sales. Based on the market indicators and our crude oil throughput, we estimate a net positive impact of approximately $300 million on Refining & Marketing margin, primarily due to higher crack spreads, partially offset by narrower sour and sweet crude oil differentials. Our reported Refining & Marketing margin differs from market indicators due to the mix of crudes purchased and their costs, the effects of market structure on our crude oil acquisition prices, RIN prices on the crack spread and other items like refinery yields and other feedstock variances, direct dealer fuel margin, and for 2025, a LIFO inventory adjustment of $82 million and for 2024, a LIFO inventory adjustment of $106 million. These factors had an estimated net positive impact on Refining & Marketing segment adjusted EBITDA of approximately $1.0 billion in 2025 compared to 2024.
We purchase RINs to satisfy a portion of our RFS compliance. Our expenses associated with purchased RINs were $1.33 billion in 2025 and $1.07 billion in 2024 and are included in Refining & Marketing margin. The increase in 2025 was primarily due to increased obligated volumes and RINs prices, partially offset by higher RINs generated and acquired from our Martinez Renewables JV. In addition, MPC was granted an SRE for one of our refineries for 50 percent of the renewable volume obligation for the 2024 compliance year. There is an additional credit for the closed 2023 compliance year recognized in items not allocated to the segments.
For the year ended December 31, 2025, refining operating costs, excluding depreciation and amortization, were $6.10 billion. This was an increase of $385 million, compared to the year ended December 31, 2024, largely due to higher energy and maintenance and repair costs and the absence of a property tax appeal settlement received in 2024 related to retroactive tax assessments for prior periods.
Distribution costs, excluding depreciation and amortization, were $6.19 billion and $5.86 billion for 2025 and 2024, respectively, and include fees paid to MPLX of $4.03 billion and $3.95 billion for 2025 and 2024, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, increased $0.19 primarily due to an increase in logistics fees including third party marine, pipeline and terminalling costs.
Refining planned turnaround costs increased $117 million, or $0.08 per barrel, due to the scope and timing of turnaround activity.
Other income decreased by $0.15 per barrel largely due to lower insurance proceeds in 2025.
2024 Compared to 2023
Refining & Marketing segment revenues decreased $10.21 billion primarily due to a decrease in average refined product sales prices of $0.24 per gallon, partially offset by increased refined product sales volumes of 75 mbpd.
Refinery crude oil capacity utilization was 92 percent during 2024 and net refinery throughput increased 19 mbpd in 2024.
Refining & Marketing segment adjusted EBITDA decreased $8.0 billion primarily driven by decreased per barrel margins.
Refining & Marketing margin was $16.01 per barrel for 2024 compared to $23.00 per barrel for 2023. Refining & Marketing margin is affected by the market indicators shown earlier, which use spot market values and an estimated mix of crude purchases and product sales. Based on the market indicators and our crude oil throughput, we estimate a net negative impact of approximately $7 billion on Refining & Marketing margin, primarily due to lower crack spreads. Our reported Refining & Marketing margin differs from market indicators due to the mix of crudes purchased and their costs, the effects of market structure on our crude oil acquisition prices, RIN prices on the crack spread and other items like refinery yields and other feedstock variances, direct dealer fuel margin, and for 2024, a LIFO inventory adjustment of $106 million and for 2023, a LIFO inventory adjustment of $157 million. These factors had an estimated net negative impact on Refining & Marketing segment adjusted EBITDA of approximately $200 million in 2024 compared to 2023.
We purchase RINs to satisfy a portion of our RFS compliance. Our expenses associated with purchased RINs were $1.07 billion in 2024 and $2.07 billion in 2023 and are included in Refining & Marketing margin. The decrease in 2024 was primarily due to lower average RIN prices, increased RINs generated and acquired from our Martinez Renewables joint venture and lower RIN sale activity.
For the year ended December 31, 2024, refining operating costs, excluding depreciation and amortization, were $5.71 billion. This was an increase of $87 million, compared to the year ended December 31, 2023, primarily driven by higher expenses for
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projects conducted during turnaround activity, partially offset by a property tax appeal settlement related to retroactive tax assessments for prior periods.
Distribution costs, excluding depreciation and amortization, were $5.86 billion and $5.65 billion for 2024 and 2023, respectively, and include fees paid to MPLX of $3.95 billion and $3.84 billion for 2024 and 2023, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, increased $0.15 primarily due to higher pipeline tariff rates and logistics fee escalations.
Refining planned turnaround costs increased $216 million, or $0.20 per barrel, due to the scope and timing of turnaround activity.
Other income decreased by $0.19 per barrel mainly due to lower insurance proceeds in 2024.
Supplemental Refining & Marketing Statistics
Refining & Marketing Operating Statistics
Crude oil capacity utilization percent (a)
Refinery throughputs ( mbpd ):
Crude oil refined
Other charge and blendstocks
Net refinery throughput
Sour crude oil throughput percent
Sweet crude oil throughput percent
Refined product yields ( mbpd ):
Gasoline
Distillates
Propane
NGLs and petrochemicals
Heavy fuel oil
Asphalt
Total
Refined product export sales volumes (mbpd) (b)
(a) Based on calendar-day capacity, which is an annual average that includes down time for planned maintenance and other normal operating activities.
(b) Represents fully loaded export cargoes for each time period. These sales volumes are included in the total sales volumes amounts.
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Midstream
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) On owned common-carrier pipelines, excluding equity method investments.
(b) Includes operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for partnership-operated equity method investments.
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Benchmark Prices
Natural Gas NYMEX HH ( per MMBtu )
C2 + NGL Pricing ( per gallon ) (a)
(a) For 2025 and 2024, C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 10 percent ethane, 60 percent propane, five percent Iso-Butane, 15 percent normal butane and 10 percent natural gasoline. For 2023, C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
2025 Compared to 2024
Midstream segment adjusted EBITDA increased $206 million, which includes contributions from recent acquisitions, primarily $59 million related to the BANGL Acquisition and $15 million related to the Whiptail Midstream Acquisition, partially offset by $17 million resulting from the divestiture of the Rockies operations. Additionally, sales and operating revenues increased $540 million resulting from higher rates and throughputs and a $37 million non-recurring benefit associated with a customer agreement, partially offset by higher operating expenses.
2024 Compared to 2023
Midstream segment adjusted EBITDA increased $373 million. Sales and operating revenues increased $486 million mainly due to rate escalations, contributions from recently acquired assets and higher natural gas gathering and processing volumes. Income from equity method investments increased approximately $35 million.
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Renewable Diesel
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) Includes intersegment sales to the Refining & Marketing segment.
(b Includes Dickinson facility production and purchased product from our Martinez Renewables joint venture.
2025 Compared to 2024
Renewable Diesel segment revenues increased $726 million primarily due to increased sales volume of 187 thousand gallons per day. Renewable Diesel segment adjusted EBITDA increased $40 million as lower product margins were more than offset by an increase in utilization of our facilities, higher regulatory benefit and increased income from equity method investments. Reduced production capacity in 2024 due to an event at the refinery in late 2023 resulted in lower throughput and impacted margins. Renewable Diesel margins were $151 million in 2025 and $186 million in 2024.
See “Non-GAAP Financial Measures” section for reconciliation of Renewable Diesel margin.
2024 Compared to 2023
Renewable Diesel segment revenues increased $440 million primarily due to increased sales volume of 419 thousand gallons per day. Renewable Diesel segment adjusted EBITDA decreased $86 million as reduced production capacity in 2024 due to an event at the refinery in late 2023 resulted in lower throughput and impacted margins. The lower renewable diesel margins, which were $186 million in 2024 and $304 million in 2023, were partially offset by increased income from equity method investments of $129 million.
See “Non-GAAP Financial Measures” section for reconciliation of Renewable Diesel margin.
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Corporate
(millions of dollars)
Corporate (a)
(a) Corporate costs consist primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets, except for corporate overhead expenses attributable to MPLX, which are included in the Midstream segment. Corporate costs include depreciation and amortization of $105 million, $90 million and $100 million for the years ended December 31, 2025, 2024 and 2023, respectively.
2025 Compared to 2024
Corporate expenses increased $63 million in 2025 compared to 2024 largely due to an increase in contract services of $52 million.
2024 Compared to 2023
Corporate expenses increased $27 million in 2024 compared to 2023 largely due to increases in contract services of $35 million, office expenses of $24 million and compensation expense of $21 million, partially offset by a decrease in stock-based compensation of $52 million.
Items not Allocated to Segments
Our CODM evaluates the performance of our segments using segment adjusted EBITDA. Items identified in the table below are either believed to be non-recurring in nature or not believed to be allocable, controlled by the segment or are not tied to the operational performance of the segment.
(millions of dollars)
Items not allocated to segments:
Gain on sale of assets
SRE
Transaction-related costs
Legal settlements
Total items not allocated to segments
2025 Compared to 2024
In 2025, total items not allocated to segments of $1.17 billion primarily includes gain on sale of assets of $897 million, which includes gains from the BANGL Acquisition of $484 million, the Ethanol Joint Venture Sale of $254 million and the divestiture of the Rockies operations of $159 million. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on these transactions. In addition, items not allocated to segments in 2025 includes legal settlements of $253 million and the 2023 compliance year SRE credit, partially offset by transaction costs related to Midstream acquisitions during the year. In 2024, items not allocated to segments includes a $151 million gain resulting from the Whistler Joint Venture Transaction.
2024 Compared to 2023
In 2024, items not allocated to segments includes a $151 million gain resulting from the Whistler Joint Venture Transaction. In 2023, total items not allocated to segments includes the $106 million gain on the sale of MPC’s 25 percent interest in South Texas Gateway and the $92 million gain associated with the remeasurement of MPLX’s existing equity investment in Torñado arising from the acquisition of the remaining 40 percent interest.
Non-GAAP Financial Measures
Management uses financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with GAAP. The non-GAAP financial measures we use are as follows:
Refining & Marketing Margin
Refining & Marketing margin is defined as sales revenue less cost of refinery inputs and purchased products. We use and believe our investors use this non-GAAP financial measure to evaluate our Refining & Marketing segment’s operating and financial performance as it is the most comparable measure to the industry’s market reference product margins. This measure should not be considered a substitute for, or superior to, Refining & Marketing gross margin or other measures of financial performance prepared in accordance with GAAP, and our calculations thereof may not be comparable to similarly titled measures reported by other companies.
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Reconciliation of Refining & Marketing segment adjusted EBITDA to Refining & Marketing gross margin and Refining & Marketing margin
(Millions of dollars)
Refining & Marketing segment adjusted EBITDA
Plus (Less):
Depreciation and amortization
Refining planned turnaround costs
LIFO inventory adjustment
Selling, general and administrative expenses
Income from equity method investments
Net (gain) loss on disposal of assets
Other income
Refining & Marketing gross margin
Plus (Less):
Operating expenses (excluding depreciation and amortization)
Depreciation and amortization
Gross margin excluded from and other income included in Refining & Marketing margin (a)
Other taxes included in Refining & Marketing margin
Refining & Marketing margin
(a) Reflects the gross margin, excluding depreciation and amortization, of other related operations included in the Refining & Marketing segment and processing of credit card transactions on behalf of certain of our marketing customers, net of other income.
Renewable Diesel Margin
Renewable Diesel margin is defined as sales revenue plus value attributable to qualifying regulatory credits earned during the period less cost of renewable inputs and purchased products. We use and believe our investors use this non-GAAP financial measure to evaluate our Renewable Diesel segment’s operating and financial performance. This measure should not be considered a substitute for, or superior to, Renewable Diesel gross margin or other measures of financial performance prepared in accordance with GAAP, and our calculation thereof may not be comparable to similarly titled measures reported by other companies.
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Reconciliation of Renewable Diesel segment adjusted EBITDA to Renewable Diesel gross margin and Renewable Diesel margin
(Millions of dollars)
Renewable Diesel segment adjusted EBITDA
Plus (Less):
Depreciation and amortization
Renewable Diesel JV depreciation and amortization (a)
Renewable Diesel planned turnaround costs
Renewable Diesel JV planned turnaround costs (a)
LIFO inventory adjustment
Selling, general and administrative expenses
(Income) loss from equity method investments
Net gain on disposal of assets
Other income
Renewable Diesel gross margin
Plus (Less):
Operating expenses (excluding depreciation and amortization)
Depreciation and amortization
Martinez JV depreciation and amortization
Renewable Diesel margin
(a) Represents MPC’s pro-rata share of expenses from joint ventures included within the Renewable Diesel segment.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash and cash equivalents balance was $3.67 billion at December 31, 2025, compared to $3.21 billion at December 31, 2024. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years is presented in the following table.
(Millions of dollars)
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Total increase (decrease) in cash
Operating Activities
Net cash provided by operating activities decreased $412 million in 2025 compared to 2024, primarily due to an unfavorable change in working capital of $955 million, partially offset by an increase in operating results. Net cash provided by operating activities decreased $5.45 billion in 2024 compared to 2023, primarily due to a decrease in operating results partially offset by a favorable change in working capital of $105 million. The above changes in working capital exclude changes in short-term debt.
For 2025, changes in working capital were a net $485 million use of cash, primarily due to the effect of decreases in energy commodity prices, partially offset by increases in volumes at the end of the year on working capital. Accounts payable decreased primarily due to decreases in crude oil prices, partially offset by increases in crude oil volumes. Current receivables decreased primarily due to decreases in crude oil and refined product prices and income tax receivables, partially offset by an increase in crude oil volumes. Inventories increased primarily due to increases in materials and supplies and refined product inventories. Additionally, working capital was favorably impacted by changes in current liabilities and other current assets.
For 2024, changes in working capital were a net $470 million source of cash, primarily due to the effect of decreases in energy commodity prices and volumes at the end of the year on working capital. Current receivables decreased primarily due to decreases in refined product and crude oil prices and crude oil volumes. Accounts payable increased primarily due to increased crude oil volumes and liability for a purchase of tax credits from a third party, partially offset by decreased crude oil prices. Inventories increased primarily due to increases in refined product and materials and supplies inventories, partially offset by a
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decrease in crude oil inventory. Additionally, working capital was favorably impacted by changes in income tax receivable and unfavorably impacted by changes in current liabilities and other current assets.
For 2023, changes in working capital were a net $365 million source of cash, primarily due to the effect of decreases in energy commodity prices and volumes at the end of the year on working capital. Current receivables decreased primarily due to decreases in crude oil volumes and prices. Accounts payable decreased primarily due to decreases in crude oil prices and volumes. Inventories increased primarily due to increases in refined product, crude oil and materials and supplies inventories. Additionally, working capital was favorably impacted by changes in income tax receivable and current liabilities and other current assets.
Investing Activities
Net cash used in investing activities was $5.87 billion in 2025 and $3.10 billion in 2023, compared to net cash provided by investing activities of $1.53 billion in 2024.
• Short-term investments were liquidated in the fourth quarter of 2024 and, therefore, there was no activity related to short-term investments in 2025. In 2024, the change in net cash provided was primarily due to maturities and sales of short-term investments of $4.53 billion and $3.30 billion, respectively, partially offset by purchases of short-term investments of $2.95 billion. The cash provided by maturities and sales of short-term investments was primarily used to fund our return of capital initiatives.
• In 2023, the change in net cash used was primarily due to purchases of short-term investments of $8.62 billion, partially offset by maturities and sales of short-term investments of $5.05 billion and $2.08 billion, respectively. The cash provided by maturities and sales of short-term investments was primarily used to fund our return of capital initiatives announced as part of the Speedway sale.
• Cash used for additions to property, plant and equipment was $3.49 billion in 2025, compared to $2.53 billion in 2024 and $1.89 billion in 2023. See the “Capital Requirements” section for additional information on our capital investment plan.
• Cash used for acquisitions was $3.32 billion in 2025 and $688 million in 2024 largely due to acquisitions in our Midstream segment, including $2.4 billion for the Northwind Midstream Acquisition, $703 million for the BANGL Acquisition and $235 million for the Whiptail Midstream Acquisition. Cash used for acquisitions in 2024 included $625 million of cash to purchase additional ownership interests in existing Midstream joint ventures and gathering assets. Cash used for acquisitions was $246 million in 2023 due to MPLX’s acquisition of the remaining interest in a gathering and processing joint venture for approximately $270 million, offset by cash acquired of $24 million.
• Cash used in net investments was $343 million in 2025, $348 million in 2024 and $205 million in 2023. In 2025, investments mainly included contributions to Midstream equity method investments, partially offset by proceeds from the Ethanol Joint Venture Sale and a return of capital of $150 million related to a Midstream joint venture. In 2024, investments primarily included a return of capital of $134 million related to the Whistler Joint Venture Transaction which was more than offset by Midstream equity method investments, including a $92 million contribution made in March 2024 for the repayment of MPLX’s share of the Dakota Access joint venture’s debt due in 2024. In 2023, investments primarily included the Martinez Renewables joint venture and the acquisition of a 49.9 percent equity interest in LF Bioenergy for approximately $56 million, partially offset by cash received from the sale of MPC’s 25 percent interest in South Texas Gateway.
• Cash provided by disposal of assets totaled $1.01 billion, $35 million and $36 million in 2025, 2024 and 2023, respectively, primarily due to the divestiture of the Rockies operations in 2025, the sale of Corporate and Refining & Marketing assets in 2024 and the sale of Midstream assets in 2023.
The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. A reconciliation of additions to property, plant and equipment to total capital expenditures and investments follows for each of the last three years.
(Millions of dollars)
Additions to property, plant and equipment per consolidated statements of cash flows
Increase in capital accruals
Total capital expenditures
Investments in equity method investees
Total capital expenditures and investments
Financing Activities
Financing activities were a use of cash of $1.92 billion in 2025, $12.43 billion in 2024 and $14.21 billion in 2023.
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• During 2025, MPLX issued $6.5 billion aggregate principal amount of senior notes and repaid $1.70 billion aggregate principal amount of senior notes and MPC issued $2.0 billion in aggregate principal amount of senior notes and repaid $1.250 billion in aggregate principal amount of senior notes.
• During 2024, MPLX issued $1.65 billion aggregate principal amount of 5.50 percent senior notes due June 2034 and used the proceeds to repay $1.15 billion aggregate principal amount of senior notes. MPC repaid $750 million aggregate principal amount of senior notes that matured September 2024.
• During 2023, MPLX issued $1.6 billion of senior notes and used the proceeds to redeem $1.0 billion of senior notes and all of its outstanding Series B preferred units for $600 million.
• Cash used in common stock repurchases totaled $3.49 billion in 2025, $9.19 billion in 2024 and $11.57 billion in 2023. See the “Capital Requirements” section for further discussion of our stock repurchases.
• Cash used in dividend payments totaled $1.14 billion in 2025, $1.15 billion in 2024 and $1.26 billion in 2023. Dividends per share were $3.73 in 2025, $3.39 in 2024 and $3.08 in 2023. The decreases in 2025 and 2024 are primarily due to share repurchases, partially offset by increases in per share dividends.
• Cash used in distributions to noncontrolling interests totaled $1.51 billion in 2025, $1.38 billion in 2024 and $1.28 billion in 2023 due to distributions to MPLX common and preferred public unitholders.
• Cash used in repurchases of noncontrolling interests totaled $400 million in 2025 and $326 million in 2024 due to MPLX’s repurchases of its common units. There were no repurchases of noncontrolling interests in 2023. See the “Capital Requirements” section for further discussion of MPLX’s unit repurchases.
Derivative Instruments
See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative instruments and associated market risk.
Capital Resources
MPC, Excluding MPLX
We control MPLX through our ownership of the general partner; however, the creditors of MPLX do not have recourse to MPC’s general credit through guarantees or other financial arrangements, except as noted. MPC has effectively guaranteed certain indebtedness of LOOP and LOCAP, in which MPLX holds an interest. Therefore, in the following table, we present the liquidity of MPC, excluding MPLX. MPLX liquidity is discussed in the following section.
Our liquidity, excluding MPLX, totaled $6.63 billion at December 31, 2025 consisting of:
December 31, 2025
(Millions of dollars)
Total Capacity
Outstanding Borrowings
Outstanding Letters
of Credit
Available
Capacity
Bank revolving credit facility
Trade receivables facility (a)
Total
Cash and cash equivalents and short-term investments (b)
Total liquidity
(a) The committed borrowing and letter of credit issuance capacity under the trade receivables securitization facility is $100 million. In addition, the facility allows for the issuance of letters of credit in excess of the committed capacity at the discretion of the issuing banks.
(b) Excludes $2.14 billion of MPLX cash and cash equivalents.
Because of the alternatives available to us, including internally generated cash flow and access to capital markets and a commercial paper program, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term (less than twelve months) and long-term funding requirements, including capital spending programs, the repurchase of shares of our common stock, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.
On February 10, 2025, MPC issued $2.0 billion aggregate principal amount of senior notes in an underwritten public offering (“2025 Senior Notes Offering”), consisting of:
• $1.1 billion aggregate principal amount of 5.150 percent senior notes due March 2030; and
• $900 million aggregate principal amount of 5.700 percent senior notes due March 2035.
The 2025 Senior Note Offering replaced the $750 million aggregate principal amount of 3.625 percent senior notes that matured in September 2024 and was used to repay the $1.250 billion aggregate principal amount of 4.700 percent senior notes at maturity on May 1, 2025.
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We have a commercial paper program that allows us to have a maximum of $2.0 billion in commercial paper outstanding, with maturities up to 397 days from the date of issuance. We do not intend to have outstanding commercial paper borrowings in excess of available capacity under our bank revolving credit facility. At December 31, 2025, we had no borrowings outstanding under the commercial paper program.
MPC’s bank revolving credit facility and trade receivables facility contain representations and warranties, affirmative and negative covenants and restrictions, including financial covenants, and events of default that we consider usual and customary for agreements of a similar type and nature. As of December 31, 2025, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPC’s revolving bank credit facility, trade receivables facility and related covenants and restrictions.
Our intention is to maintain an investment-grade credit profile. As of January 31, 2026, the credit ratings on our senior unsecured debt are as follows.
Company
Rating Agency
Rating
MPC
Moody’s
Baa2 (stable outlook)
Standard & Poor’s
BBB (stable outlook)
Fitch
BBB (stable outlook)
The ratings reflect the respective views of the rating agencies and should not be interpreted as a recommendation to buy, sell or hold our securities. Although it is our intention to maintain a credit profile that supports an investment-grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.
The agreements governing MPC’s debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades of our senior unsecured debt could increase the applicable interest rates, yields and other fees payable under such agreements and may limit our flexibility to obtain financing in the future, including to refinance existing indebtedness. In addition, a downgrade of our senior unsecured debt rating to below investment-grade levels could, under certain circumstances, impact our ability to purchase crude oil on an unsecured basis and could result in us having to post letters of credit under existing transportation services or other agreements.
See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of our debt.
MPLX
MPLX’s liquidity totaled $5.64 billion at December 31, 2025 consisting of:
December 31, 2025
(Millions of dollars)
Total Capacity
Outstanding Borrowings
Outstanding Letters
of Credit
Available
Capacity
MPLX bank revolving credit facility
MPC intercompany loan agreement
Total
Cash and cash equivalents
Total liquidity
On February 18, 2025, MPLX repaid all of MPLX's outstanding $500 million aggregate principal amount of 4.000 percent senior notes due February 2025 at maturity.
On March 10, 2025, MPLX issued $2.0 billion in aggregate principal amount of senior notes in an underwritten public offering (“March 2025 MPLX Senior Notes”), consisting of:
• $1.0 billion aggregate principal amount of 5.400 percent senior notes due April 2035; and
• $1.0 billion aggregate principal amount of 5.950 percent senior notes due April 2055.
On April 9, 2025, MPLX used a portion of the net proceeds from the March 2025 MPLX Senior Notes Offering to redeem all of (i) MPLX LP’s outstanding $1,189 million aggregate principal amount of 4.875 percent senior notes due June 2025 and (ii) MarkWest Energy Partners, L.P.’s outstanding $11 million aggregate principal amount of 4.875 percent senior notes due June 2025. MPLX used the remaining net proceeds for general partnership purposes.
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On July 3, 2025, MPLX used cash on hand to extinguish approximately $656 million principal amount of debt outstanding, including interest, related to certain term and revolving loans assumed as part of the BANGL Acquisition. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on this transaction.
On August 11, 2025, MPLX issued $4.5 billion in aggregate principal amount of senior notes in an underwritten public offering (“August 2025 MPLX Senior Notes Offering”), consisting of:
• $1.25 billion aggregate principal amount of 4.800 percent senior notes due February 2031;
• $750 million aggregate principal amount of 5.000 percent senior notes due January 2033;
• $1.5 billion aggregate principal amount of 5.400 percent senior notes due September 2035; and
• $1.0 billion aggregate principal amount of 6.200 percent senior notes due September 2055.
MPLX used a portion of the net proceeds from the August 2025 MPLX Senior Notes Offering to fund the Northwind Midstream Acquisition and incremental capital expenditures associated with in-process expansion projects, including the payment of related fees and expenses, and to increase cash and cash equivalents following the recently completed BANGL Acquisition and BANGL Debt Repayment. The remainder of the net proceeds from the August 2025 MPLX Senior Notes Offering were used for general partnership purposes.
On February 12, 2026, MPLX issued $1.5 billion aggregate principal amount of senior notes in an underwritten public offering, consisting of $1.0 billion aggregate amount of 5.300 percent senior notes due April 2036 and $500 million aggregate principal amount of 6.100 percent senior notes due April 2056. MPLX intends to use the net proceeds from this offering to repay MPLX’s outstanding $1.5 billion aggregate principal amount of 1.750 percent senior notes due March 2026 at maturity. Pending final use, MPLX may invest the proceeds in short-term marketable securities or other investments.
MPLX’s bank revolving credit facility contains representations and warranties, covenants and restrictions, including financial covenants, and events of default that we consider usual and customary for agreements of a similar type and nature. As of December 31, 2025, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPLX’s bank revolving credit facility and related covenants and restrictions.
Our intention is to maintain an investment-grade credit profile for MPLX. As of January 31, 2026, the credit ratings on MPLX’s senior unsecured debt are as follows.
Company
Rating Agency
Rating
MPLX
Moody’s
Baa2 (stable outlook)
Standard & Poor’s
BBB (stable outlook)
Fitch
BBB (stable outlook)
The ratings reflect the respective views of the rating agencies and should not be interpreted as a recommendation to buy, sell or hold MPLX securities. Although it is our intention to maintain a credit profile that supports an investment-grade rating for MPLX, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.
The agreements governing MPLX’s debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that MPLX credit ratings are downgraded. However, any downgrades of MPLX senior unsecured debt to below investment grade ratings could increase the applicable interest rates, yields and other fees payable under such agreements. In addition, a downgrade of MPLX senior unsecured debt ratings to below investment-grade levels may limit MPLX’s ability to obtain future financing, including to refinance existing indebtedness.
See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPLX’s debt.
Capital Requirements
Capital Spending
MPC’s capital investment outlook for 2026 totals approximately $1.5 billion for capital projects and investments, excluding capitalized interest, potential acquisitions, if any, and MPLX’s capital investment plan. MPC’s 2026 capital investment outlook includes all of the planned capital spending for Refining & Marketing, Renewable Diesel and Corporate as well as a portion of the planned capital investments for Midstream. The remainder of the planned capital spending for Midstream reflects the capital investment plan for MPLX. We continuously evaluate our capital plan and make changes as conditions warrant. The 2026 capital investment outlook for MPC and MPLX and capital expenditures and investments for each of the last three years are summarized by segment below.
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(Millions of dollars)
2026 Outlook
Capital expenditures and investments: (a)
MPC, excluding MPLX
Refining & Marketing
Midstream - Other
Renewable Diesel
Corporate and Other (b)
Total MPC, excluding MPLX
Midstream - MPLX (c)(d)
(a) Capital expenditures include changes in capital accruals.
(b) Excludes capitalized interest of $94 million, $56 million and $55 million for 2025, 2024 and 2023, respectively. The 2026 capital investment plan excludes capitalized interest.
(c) The 2026 capital investment outlook for Midstream - MPLX excludes $260 million of capital expenditures, which is expected to be incurred primarily by MPC and other MPLX customers on MPLX’s behalf. This reimbursable capital will be included in the 2026 MPC Midstream capital expenditures.
(d) Includes reimbursable capital of $168 million, $163 million and $196 million for 2025, 2024 and 2023, respectively.
Refining & Marketing
The Refining & Marketing segment’s forecasted 2026 capital spending and investments is approximately $1.41 billion. This amount includes approximately $710 million for Refining value enhancing capital projects and $250 million for Marketing investments to strengthen our retail portfolio. Our capital investment outlook for Refining includes continued high-return investments at its Galveston Bay, Robinson, El Paso, and Garyville refineries. In addition to these multi-year investments, we are executing shorter-term projects that offer high returns through margin enhancement and cost reduction. Our capital investment outlook for Marketing includes continuing to expand the reach and presence of our branded stations in support of strong value capture. Refining m aintenance capital is expected to be approximately $450 million, which is essential to maintain the safety, integrity and reliability of our assets.
Major capital projects completed over the last three years have focused on refinery optimization, production of higher value products, increased capacity to upgrade residual fuel oil and expanded export capacity. We executed on projects such as the STAR project at our Galveston Bay refinery, the utility modernization project at the Los Angeles refinery and projects expected to reduce future operating costs.
Midstream
MPLX’s capital investment outlook totals approximately $2.7 billion, net of reimbursements and excluding capitalized interest and potential acquisitions, if any, and includes approximately $2.4 billion of growth capital and $300 million of maintenance capital. MPLX’s growth capital plans are focused on expanding its Permian to Gulf Coast integrated value chain, progressing long-haul pipeline growth projects to support producer activity, and investing in new gas processing plants in the Marcellus and Permian. The remainder of its capital plan targets debottlenecking of existing assets to meet customer demand.
Major capital projects over the last three years included investments for the development of natural gas and natural gas liquids infrastructure to support MPLX’s producer customers, primarily in the Marcellus, Utica and Permian regions and development of various crude oil and refined petroleum products infrastructure projects.
The remaining Midstream segment’s capital investment outlook, excluding MPLX, is approximately $40 million.
Renewable Diesel
There is no major forecasted 2026 capital spending and investments for the Renewable Diesel segment. Major projects over the last three years included investments in the Martinez Renewables joint venture and the Green Bison Soy Processing joint venture.
Corporate and Other
The 2026 capital forecast includes approximately $50 million to support corporate and other activities. Major projects over the last three years included upgrades to information technology systems.
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Share Repurchases
From January 1, 2012 through December 31, 2025, our board of directors approved $60.05 billion in total share repurchase authorizations and we have repurchased a total of $55.67 billion of our common stock. As of December 31, 2025, MPC had $4.38 billion remaining under its share repurchase authorization. The table below summarizes our total share repurchases for the last three years. See Item 8. Financial Statements and Supplementary Data – Note 9 for further discussion of the share repurchase plans.
(In millions, except per share data)
Number of shares repurchased
Cash paid for shares repurchased (a)
Average cost per share (b)
(a) 2025 excludes $89 million paid in 2025 for excise tax on 2024 share repurchases. 2024 excludes $112 million paid in 2024 for excise tax on 2023 share purchases.
(b) The average cost per share includes excise tax on share repurchases resulting from the Inflation Reduction Act of 2022, but the excise tax does not reduce the remaining share repurchase authorization.
We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be suspended or discontinued at any time.
MPLX Unit Repurchases
The table below summarizes MPLX’s total unit repurchases for the last three years.
(In millions, except per unit data)
Number of common units repurchased
Cash paid for common units repurchased
Average cost per unit
As of December 31, 2025, MPLX had approximately $1.12 billion remaining under its unit repurchase authorizations. The repurchase authorizations have no expiration date.
MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
See Item 8. Financial Statements and Supplementary Data – Note 4 for further discussion of the MPLX unit repurchase program.
Material Cash Commitments
Contractual Obligations
We have purchase commitments primarily consisting of obligations to purchase and transport crude oil and feedstocks used in our refining operations. As of December 31, 2025, we had purchase obligations for crude oil, NGLs and renewable feedstocks of $12.04 billion, with $10.15 billion payable within 12 months, and crude oil transportation obligations of $8.87 billion, with $875 million payable within 12 months. These contracts include variable price arrangements. For purposes of this disclosure, we have estimated prices to be paid primarily based on futures curves for the commodities to the extent available. Our contractual obligations do not include our contractual obligations to MPLX under various fee-based commercial agreements as these transactions are eliminated in the consolidated financial statements.
At December 31, 2025, our contractual commitment under contracts to acquire property, plant and equipment was $453 million, with $446 million payable within 12 months.
At December 31, 2025, we had an aggregate principal amount of outstanding senior notes of $32.45 billion, with $2.25 billion payable within 12 months, and interest on the debt of $21.62 billion, with $1.56 billion payable within 12 months. See Item 8. Financial Statements and Supplementary Data – Note 19 for additional information on our debt. We intend to repay the short-term maturities with existing cash on hand and/or with the proceeds of new long-term debt, depending on, among other things, market conditions.
Our other contractual obligations primarily consist of pension and post-retirement obligations, finance and operating leases and environmental credits liabilities, for which additional information is included in Item 8. Financial Statements and Supplementary Data – Notes 24, 26 and 22, respectively.
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Other Cash Commitments
On January 30, 2026, we announced our board of directors approved a $1.00 per share dividend, payable March 10, 2026 to shareholders of record at the close of business on February 18, 2026.
We may, from time to time, repurchase our senior notes and preferred units in the open market, in tender offers, in privately-negotiated transactions or otherwise in such volumes, at such prices and upon such other terms as we deem appropriate.
TRANSACTIONS WITH RELATED PARTIES
See Item 8. Financial Statements and Supplementary Data – Note 7 for discussion of activity with related parties.
ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS
We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.
Legislation and regulations pertaining to fuel specifications, climate change and GHG emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers.
Our environmental expenditures, including non-regulatory expenditures, for each of the last three years were:
(Millions of dollars)
Capital
Compliance: (a)
Operating and maintenance
Remediation (b)
Total
(a) Based on the American Petroleum Institute’s definition of environmental expenditures.
(b) These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. It is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Our environmental capital expenditures accounted for 20 percent, 22 percent and 12 percent of capital expenditures for 2025, 2024 and 2023, respectively, excluding acquisitions. Our environmental capital expenditures are expected to be approximately $183 million, or 4 percent, of total planned capital expenditures in 2026. Actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Regulatory Matters and Item 1A. Risk Factors.
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CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. See Item 8. Financial Statements and Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use an income or market approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data – Note 17 for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
• assessment of impairment of long-lived assets, intangible assets, goodwill and equity method investments;
• recorded values for assets acquired and liabilities assumed in connection with acquisitions; and
• recorded values of derivative instruments.
Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method Investments
Fair value calculated for the purpose of testing our long-lived assets, intangible assets, goodwill and equity method investments for impairment is estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted financial information prepared using significant assumptions including:
• Future operating performance . Our estimates of future operating performance are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions, as well as commodity prices. Such estimates are consistent with those used in our planning and capital investment reviews.
• Future volumes. Our estimates of future refinery, pipeline throughput and natural gas and natural gas liquid processing volumes are based on internal forecasts prepared by our Refining & Marketing and Midstream segments operations personnel. Assumptions about our customers’ drilling activity are inherently subjective and contingent upon a number of variable factors (including future or expected crude oil and natural gas pricing considerations), many of which are
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difficult to forecast. Management considers these volume forecasts and other factors when developing our forecasted cash flows.
• Discount rate commensurate with the risks involved . We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
• Future capital requirements . These are based on authorized spending and internal forecasts.
Assumptions about the macroeconomic environment are inherently subjective and difficult to forecast. We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for products produced, a weakened outlook for profitability, a significant reduction in pipeline throughput volumes, a significant reduction in natural gas or natural gas liquids processed, a significant reduction in refining margins, other changes to contracts or changes in the regulatory environment. The following sections detail our critical accounting estimates related to impairment assessments for long-lived assets, goodwill and equity method investments.
Long-lived Asset Impairment Assessments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is the refinery and associated distribution system level for Refining & Marketing segment assets, and the plant level or pipeline system level for Midstream segment assets. If the sum of the undiscounted estimated pretax cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down to the calculated fair value.
Goodwill Impairment Assessments
Unlike long-lived assets, goodwill must be tested for impairment at least annually, and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We have seven reporting units, five of which have goodwill allocated to them. A goodwill impairmentloss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, without exceeding the recorded amount of goodwill.
At December 31, 2025, MPC had five reporting units with goodwill totaling approximately $9.35 billion. For the annual impairment assessment as of November 30, 2025, management performed only qualitative assessments for all five reporting units as we determined it was more likely than not that the fair values of the reporting units exceeded their carrying values. See Item 8. Financial Statements and Supplementary Data – Note 16 for additional information relating to our reporting units and goodwill.
Equity Method Investment Impairment Assessment
Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At December 31, 2025, we had $6.80 billion of investments in equity method investments recorded on our consolidated balance sheet.
See Item 8. Financial Statements and Supplementary Data – Note 14 for additional information on our equity method investments. See Item 8. Financial Statements and Supplementary Data – Note 16 for additional information on our goodwill and intangibles, including a table summarizing our recorded goodwill by segment.
Acquisitions
In accounting for business combinations, acquired assets, assumed liabilities and contingent consideration are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other assets and liabilities. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for valuation assistance.
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The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project future volumes and associated cash flows, and apply an appropriate discount rate; the cost approach, which may require estimates of replacement costs, reproduction costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ materially from the projected results used to determine fair value.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on our acquisitions. See Item 8. Financial Statements and Supplementary Data – Note 17 for additional information on fair value measurements.
Derivatives
We record all derivative instruments at fair value. Substantially all of our commodity derivatives are cleared through exchanges which provide active trading information for identical derivatives and do not require any assumptions in arriving at fair value. Fair value estimation for all our derivative instruments is discussed in Item 8. Financial Statements and Supplementary Data – Note 17. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:
• the discount rate for measuring the present value of future plan obligations;
• the expected long-term return on plan assets;
• the rate of future increases in compensation levels;
• health care cost projections; and
• the mortality table used in determining future plan obligations.
We utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for each of our pension plans and retiree health and welfare based on the projected benefit payment patterns of each individual plan. The selected rates are compared to various similar bond indexes for reasonableness. In determining the assumed discount rates, we use our third-party actuaries’ discount rate models. These models calculate an equivalent single discount rate for the projected benefit plan cash flows using yield curves derived from Aa or higher corporate bond yields. The yield curves represent a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used have an average rating of Aa or higher from a recognized rating agency and generally only non-callable bonds are included. Outlier bonds that have a yield to maturity that deviate significantly from the average yield within each maturity grouping are not included. Each issue is required to have at least $300 million par value outstanding.
Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the discount rates of 5.50 percent for our pension plans and 5.20 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $75 million and $15 million, respectively, would increase defined benefit pension expense by $11 million, and would decrease other postretirement benefit plan expense and by less than $1 million.
The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 50 percent equity securities and 50 percent fixed income securities for the primary funded pension plan), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation and returns. In addition, our long-term asset rate of return assumption is compared to those of other companies and to historical returns for reasonableness. We used the 7.10 percent long-term rate of return to determine our 2025 defined benefit pension expense. After evaluating activity in the capital markets, along with the current and projected plan investments, we decreased the asset rate of return for our primary plan to 6.90 percent effective for 2026. Decreasing the 7.10 percent asset rate of return assumption by 0.25 percentage points would increase our defined benefit pension expense by $5 million.
Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans.
Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.
We utilized the 2021 mortality tables from the U.S. Society of Actuaries.
