UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2025
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from to
Commission file number 001-35054
Marathon Petroleum Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 27-1284632 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
539 South Main Street, Findlay, OH 45840-3229
(Address of principal executive offices) (Zip code)
(419) 422-2121
(Registrant’s telephone number, including area code)
| Securities Registered pursuant to Section 12(b) of the Act | ||||||||
| Title of each class | Trading symbol(s) | Name of each exchange on which registered | ||||||
| Common Stock, par value $.01 | MPC | New York Stock Exchange | ||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
As of June 30, 2025, the aggregate market value of common stock held by non-affiliates was approximately $50.6 billion, based on the closing price of the registrant’s common stock on the New York Stock Exchange on June 30, 2025, the last trading day of the registrant’s most recently completed second fiscal quarter. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.
There were 294,740,164 shares of Marathon Petroleum Corporation common stock outstanding as of February 20, 2026.
Documents Incorporated by Reference
Portions of the registrant’s proxy statement relating to its 2026 Annual Meeting of Shareholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Report.
Table of Contents
| Page | ||||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 1B. | ||||||||
| Item 1C. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |||||||
| Item 7. | ||||||||
| Item 7A. | ||||||||
| Item 8. | ||||||||
| Item 9. | ||||||||
| Item 9A. | ||||||||
| Item 9B. | ||||||||
| Item 9C. | ||||||||
| Item 10. | ||||||||
| Item 11. | ||||||||
| Item 12. | ||||||||
| Item 13. | ||||||||
| Item 14. | ||||||||
| Item 15. | ||||||||
Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPC,” “us,” “our,” “we” or the “Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries.
Glossary of Terms
Throughout this report, the following company or industry specific terms and abbreviations are used:
| ANS | Alaska North Slope crude oil, an oil index benchmark price | ||||
| ASC | Accounting Standards Codification | ||||
| ASU | Accounting Standards Update | ||||
| ATB | Articulated tug barges | ||||
| barrel | One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons | ||||
| CARB | California Air Resources Board | ||||
| CARBOB | California Reformulated Gasoline Blendstock for Oxygenate Blending | ||||
| CBOB | Conventional Gasoline Blendstock for Oxygenate Blending | ||||
| EBITDA | Earnings Before Interest, Tax, Depreciation and Amortization (a non-GAAP financial measure) | ||||
| EPA | U.S. Environmental Protection Agency | ||||
| ESG | Environmental, social and governance | ||||
| FASB | Financial Accounting Standards Board | ||||
| GAAP | Accounting principles generally accepted in the United States | ||||
| GHG | Greenhouse gas | ||||
| JV | Joint Venture | ||||
| LCFS | Low Carbon Fuel Standard | ||||
| LIFO | Last in, first out | ||||
| mbbls | Thousands of barrels | ||||
| mbpd | Thousands of barrels per day | ||||
| mbpcd | Thousand barrels per calendar day | ||||
| MEH | Magellan East Houston crude oil, an oil index benchmark price | ||||
| MMBtu | One million British thermal units | ||||
| MMcf/d | One million cubic feet of natural gas per day | ||||
| MPLX | MPLX LP | ||||
| NGL | Natural gas liquids, such as ethane, butanes and natural gasoline | ||||
| NYMEX | New York Mercantile Exchange | ||||
| NYSE | New York Stock Exchange | ||||
| OSHA | U.S. Occupational Safety and Health Administration | ||||
| OTC | Over-the-Counter | ||||
| RFS | Renewable Fuel Standard program, as required by the Energy Independence and Security Act of 2007 | ||||
| RIN | Renewable Identification Number | ||||
| SEC | U.S. Securities and Exchange Commission | ||||
| SOFR | Secured overnight financing rate | ||||
| SRE | Small Refinery Exemption credit under the Renewable Fuel Standard program | ||||
| ULSD | Ultra-low sulfur diesel | ||||
| USGC | U.S. Gulf Coast | ||||
| UST | Underground storage tank | ||||
| VIE | Variable interest entity | ||||
| VPP | Voluntary Protection Program | ||||
| WTI | West Texas Intermediate crude oil, an oil index benchmark price | ||||
1
Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk includes forward-looking statements that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words such as “advance,” “anticipate,” “believe,” “commitment,” “continue,” “could,” “design,” “drive,” “endeavor,” “estimate,” “expect,” “focus,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “progress,” “project,” “prospective,” “pursue,” “seek,” “should,” “strategy,” “strive,” “support,” “target,” “trends,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.
Forward-looking statements include, among other things, statements regarding:
•future financial and operating results;
•ESG plans and goals, including those related to GHG emissions and intensity, freshwater withdraw intensity, inclusion and ESG reporting;
•future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;
•the success or timing of completion of ongoing or anticipated capital or maintenance projects;
•business strategies, growth opportunities and expected investments, including plans to improve commercial performance, lower costs and optimize our asset portfolio;
•consumer demand for refined products, natural gas, renewable diesel and other renewable fuels and NGLs;
•the timing, amount and form of any future capital return transactions, including dividends and share repurchases by MPC or distributions and unit repurchases by MPLX; and
•the anticipated effects of actions of third parties such as competitors, activist investors, federal, foreign, state or local regulatory authorities or plaintiffs in litigation.
Our forward-looking statements are not guarantees of future performance, and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. Forward-looking and other statements regarding our ESG plans and goals are not an indication that these statements are material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking ESG-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:
•general economic, political or regulatory developments, including tariffs, inflation, interest rates, governmental shutdowns, changes in governmental policies relating to refined petroleum products, crude oil, natural gas, NGLs or renewable diesel and other renewable fuels, or taxation, including changes in tax regulations or guidance promulgated pursuant to the new legislation implemented in the One Big Beautiful Bill Act;
•the regional, national and worldwide availability and pricing of refined products, crude oil, natural gas, renewable diesel and other renewable fuels, NGLs and other feedstocks;
•disruptions in credit markets or changes to credit ratings;
•the adequacy of capital resources and liquidity, including availability, timing and amounts of free cash flow necessary to execute business plans and to effect any share repurchases or to maintain or increase the dividend;
•the potential effects of judicial or other proceedings on our business, financial condition, results of operations and cash flows;
•the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products or renewable diesel and other renewable fuels;
•volatility in or degradation of general economic, market, industry or business conditions, including as a result of pandemics, other infectious disease outbreaks, natural hazards, extreme weather events, regional conflicts such as hostilities in the Middle East and in Ukraine, tariffs, inflation, or rising interest rates;
•our ability to comply with federal and state environmental, economic, health and safety, energy and other policies and regulations and enforcement actions initiated thereunder;
•adverse market conditions or other risks affecting MPLX;
•refining industry overcapacity or under capacity;
•foreign imports and exports of crude oil, refined products, natural gas and NGLs;
•the establishment or increase of tariffs on goods, including crude oil and other feedstocks imported into the United States, other trade protection measures or restrictions or retaliatory actions from foreign governments;
•changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products, other hydrocarbon-based products or renewable diesel and other renewable fuels;
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•non-payment or non-performance by our customers;
•changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks, refined products and renewable diesel and other renewable fuels;
•the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
•political and economic conditions in nations that consume refined products, natural gas, renewable diesel and other renewable fuels and NGLs, including the United States and Mexico, and in crude oil producing regions, including the Middle East, Russia, Africa, Canada and South America;
•actions taken by our competitors, including pricing adjustments, the expansion and retirement of refining capacity and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;
•completion of pipeline projects within the United States;
•changes in fuel and utility costs for our facilities;
•industrial incidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, processing, fractionation and treating facilities or equipment, means of transportation, or those of our suppliers or customers;
•acts of war, terrorism or civil unrest that could impair our ability to produce refined products, receive feedstocks or to gather, process, fractionate or transport crude oil, natural gas, NGLs, refined products or renewable diesel and other renewable fuels;
•political pressure and influence of environmental groups and other stakeholders that are adverse to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs, other hydrocarbon-based products or renewable diesel and other renewable fuels;
•labor and material shortages;
•the ability to realize expected returns or other benefits on anticipated or ongoing projects or planned or recently completed acquisitions or other transactions, including the recently completed acquisitions of Northwind Delaware Holdings LLC (the “Northwind Midstream Acquisition”) and BANGL, LLC (the “BANGL Acquisition”);
•the timing and ability to obtain necessary regulatory approvals and permits and to satisfy other conditions necessary to complete planned projects or to consummate planned transactions within the expected timeframe, if at all;
•the inability or failure of our joint venture partners to fund their share of operations and capital investments;
•the financing and distribution decisions of joint ventures we do not control;
•the availability of desirable strategic alternatives to optimize portfolio assets and the ability to obtain regulatory and other approvals with respect thereto;
•our ability to successfully implement our sustainable energy strategy and principles and achieve our ESG plans and goals within the expected timeframe, if at all;
•the costs, disruption and diversion of management’s attention associated with campaigns commenced by activist investors;
•personnel changes;
•the imposition of windfall profit taxes, maximum margin penalties, minimum inventory requirements or refinery maintenance and turnaround supply plans on companies operating in the energy industry in California or other jurisdictions; and
•the other factors described in Item 1A. Risk Factors.
We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.
3
PART I
Item 1. Business
OVERVIEW
MPC has nearly 140 years of history in the energy business, and is a leading, integrated, downstream and midstream energy company. We operate one of the nation's largest refining systems with approximately 3.0 million barrels per day of crude oil refining capacity and believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers in the United States. We distribute our refined products through one of the largest terminal operations in the United States and one of the largest private domestic fleets of inland petroleum product barges. Our integrated midstream energy asset network links producers of natural gas and NGLs from some of the largest supply basins in the United States to domestic and international markets. In addition, we are one of the largest producers and marketers of renewable diesel in the United States.
Our operations consist of three reportable operating segments: Refining & Marketing, Midstream and Renewable Diesel. Each of these segments is organized and managed based upon the nature of the products and services it offers.
•Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast, Mid-Continent and West Coast regions of the United States, purchases refined products and ethanol for resale and distributes refined products through transportation, storage, distribution and marketing services provided largely by our Midstream segment. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to independent entrepreneurs who operate primarily Marathon® branded outlets and through long-term supply contracts with direct dealers who operate locations mainly under the ARCO® brand.
•Midstream – gathers, transports, stores and distributes crude oil, refined products, including renewable diesel, and other hydrocarbon-based products principally for the Refining & Marketing segment via refining logistics assets, pipelines, terminals, towboats and barges; gathers, treats, processes and transports natural gas; and transports, fractionates, stores and markets NGLs. The Midstream segment primarily reflects the results of MPLX. MPLX is a diversified, large-cap master limited partnership (“MLP”) formed in 2012 that owns and operates midstream energy infrastructure and logistics assets and provides fuels distribution services. As of December 31, 2025, we owned the general partner of MPLX and approximately 64 percent of the outstanding MPLX common units.
•Renewable Diesel – processes renewable feedstocks into renewable diesel, markets renewable diesel and distributes renewable diesel through our Midstream segment and third parties. We sell renewable diesel to wholesale marketing customers, to buyers on the spot market and through long-term supply contracts with direct dealers who operate locations mainly under the ARCO® brand.
Corporate History and Structure
MPC was incorporated in Delaware on November 9, 2009 in connection with an internal restructuring of Marathon Oil Corporation (“Marathon Oil”). On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining, Marketing & Transportation Business into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil on June 30, 2011. Our common stock trades on the NYSE under the ticker symbol “MPC.”
On October 1, 2018, we acquired Andeavor. Andeavor shareholders received in the aggregate approximately 239.8 million shares of MPC common stock valued at $19.8 billion and $3.5 billion in cash. Andeavor was a highly integrated marketing, logistics and refining company operating primarily in the Western and Mid-Continent United States. Our acquisition of Andeavor in 2018 substantially increased our geographic diversification and the scale of our assets, which provides increased opportunities to optimize our system.
On May 14, 2021, we completed the sale of Speedway, LLC (“Speedway”), our company-owned and operated retail transportation fuel and convenience store business, to 7-Eleven, Inc. (“7-Eleven”) for cash proceeds of $21.38 billion ($17.22 billion after cash-tax payments). This transaction resulted in a pretax gain of $11.68 billion ($8.02 billion after income taxes), after deducting the book value of the net assets and certain other adjustments.
OUR OPERATIONS
Refining & Marketing
Refineries
We currently own and operate refineries in the Gulf Coast, Mid-Continent and West Coast regions of the United States with an aggregate crude oil refining capacity of 2,986 mbpcd. During 2025, our refineries processed 2,787 mbpd of crude oil and 202 mbpd of other charge and blendstocks. During 2024, our refineries processed 2,714 mbpd of crude oil and 208 mbpd of other charge and blendstocks.
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Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, hydrocracking, catalytic reforming, coking, desulfurization and sulfur recovery units. The refineries process a wide variety of condensate and light and heavy crude oils purchased from various domestic and foreign suppliers. We produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with ethanol and ULSD fuel, to heavy fuel oil and asphalt. Additionally, we manufacture NGLs and petrochemicals and propane. See the Refined Product Sales section for further information about the products we produce.
Our refineries are largely integrated with each other via pipelines, terminals and barges to maximize operating efficiency. The transportation links that connect our refineries allow the movement of intermediate products between refineries to optimize operations, produce higher margin products and efficiently utilize our processing capacity. Also, shipping intermediate products between facilities during partial refinery shutdowns allows us to utilize processing capacity that is not directly affected by the shutdown work.
Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery.
Following is a description of each of our refineries and their capacity by region.
Gulf Coast Region (1,248 mbpcd)
Galveston Bay, Texas City, Texas Refinery (631 mbpcd)
Our Galveston Bay refinery is a combination of our former Texas City refinery and Galveston Bay refinery. Following the completion of the South Texas Asset Repositioning (“STAR”) project in 2023, which added 40 mbpcd of capacity, it is now our largest refinery. The refinery is located on the Texas Gulf Coast southeast of Houston, Texas and can process a wide variety of crude oils into gasoline, distillates, NGLs and petrochemicals, heavy fuel oil and propane. The refinery has access to the export market and multiple options to sell refined products. Our cogeneration facility, which supplies the Galveston Bay refinery, currently has 1,055 megawatts of electrical production capacity and can produce 4.3 million pounds of steam per hour. Approximately 49 percent of the power generated in 2025 was used at the refinery, with the remaining electricity being sold into the electricity grid.
Garyville, Louisiana Refinery (617 mbpcd)
Our Garyville refinery is located along the Mississippi River in southeastern Louisiana between New Orleans, Louisiana and Baton Rouge, Louisiana. The Garyville refinery is configured to process a wide variety of crude oils into gasoline, distillates, NGLs and petrochemicals, propane, asphalt and heavy fuel oil. The refinery has access to the export market and multiple options to sell refined products. Our Garyville refinery has earned designation as an OSHA VPP Star site.
Mid-Continent Region (1,186 mbpcd)
Catlettsburg, Kentucky Refinery (307 mbpcd)
Our Catlettsburg refinery is located in northeastern Kentucky on the western bank of the Big Sandy River, near the confluence with the Ohio River. The Catlettsburg refinery processes sweet and sour crude oils, including production from the nearby Utica Shale, into gasoline, distillates, asphalt, NGLs and petrochemicals, propane and heavy fuel oil. Our Catlettsburg refinery has earned designation as an OSHA VPP Star site.
Robinson, Illinois Refinery (253 mbpcd)
Our Robinson refinery is located in southeastern Illinois. The Robinson refinery processes sweet and sour crude oils into gasoline, distillates, NGLs and petrochemicals, propane and heavy fuel oil. The Robinson refinery has earned designation as an OSHA VPP Star site.
Detroit, Michigan Refinery (146 mbpcd)
Our Detroit refinery is located in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes sweet and heavy sour crude oils into gasoline, distillates, NGLs and petrochemicals, asphalt, propane and heavy fuel oil. Our Detroit refinery has earned designation as an OSHA VPP Star site.
El Paso, Texas Refinery (133 mbpcd)
Our El Paso refinery is located east of downtown El Paso. The El Paso refinery processes sweet and sour crude oils into gasoline, distillates, heavy fuel oil, propane, asphalt and NGLs and petrochemicals.
St. Paul Park, Minnesota Refinery (105 mbpcd)
Our St. Paul Park refinery is located along the Mississippi River southeast of St. Paul Park. The St. Paul Park refinery processes sweet and heavy sour crude oils into gasoline, distillates, asphalt, propane, NGLs and petrochemicals and heavy fuel oil.
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Canton, Ohio Refinery (100 mbpcd)
Our Canton refinery is located south of Cleveland, Ohio. The Canton refinery processes sweet and sour crude oils, including production from the nearby Utica Shale, into gasoline, distillates, asphalt, propane, NGLs and petrochemicals and heavy fuel oil. The Canton refinery has earned designation as an OSHA VPP Star site.
Mandan, North Dakota Refinery (72 mbpcd)
Our Mandan refinery is located outside of Bismarck, North Dakota. The Mandan refinery processes primarily sweet domestic crude oil from North Dakota into gasoline, distillates, propane, heavy fuel oil and NGLs and petrochemicals.
Salt Lake City, Utah Refinery (70 mbpcd)
Our Salt Lake City refinery is the largest in Utah and is located north of downtown Salt Lake City. The Salt Lake City refinery processes crude oil from Utah, Colorado, Wyoming and Canada into gasoline, distillates, heavy fuel oil, NGLs and petrochemicals and propane.
West Coast Region (552 mbpcd)
Los Angeles, California Refinery (365 mbpcd)
Our Los Angeles refinery is located in Los Angeles County, near the Los Angeles Harbor. The Los Angeles refinery is the largest refinery on the West Coast and is a major producer of cleaner burning CARB fuels. The Los Angeles refinery processes heavy crude oil from California’s San Joaquin Valley and Los Angeles Basin, as well as crude oils from the Alaska North Slope, South America, West Africa and other international sources, into CARB gasoline and CARB diesel fuel, as well as conventional gasoline, distillates, NGLs and petrochemicals, heavy fuel oil and propane.
Anacortes, Washington Refinery (119 mbpcd)
Our Anacortes refinery is located north of Seattle on Puget Sound. The Anacortes refinery processes Canadian crude oil, domestic crude oil from North Dakota and the Alaska North Slope and international crude oils into gasoline, distillates, heavy fuel oil, propane and NGLs and petrochemicals.
Kenai, Alaska Refinery (68 mbpcd)
Our Kenai refinery is located on the Cook Inlet, southwest of Anchorage. The Kenai refinery processes mainly Alaska domestic crude oil, domestic crude oil from North Dakota, along with limited international crude oil into distillates, gasoline, heavy fuel oil, asphalt, propane and NGLs and petrochemicals.
Refined Product Yields
The following table sets forth our refinery production by product group for each of the last three years.
(mbpd) | 2025 | 2024 | 2023 | |||||||||||||||||
| Gasoline | 1,499 | 1,490 | 1,526 | |||||||||||||||||
| Distillates | 1,093 | 1,070 | 1,037 | |||||||||||||||||
| Propane | 67 | 67 | 66 | |||||||||||||||||
| NGLs and petrochemicals | 195 | 192 | 182 | |||||||||||||||||
| Heavy fuel oil | 90 | 59 | 52 | |||||||||||||||||
| Asphalt | 79 | 81 | 80 | |||||||||||||||||
| Total | 3,023 | 2,959 | 2,943 | |||||||||||||||||
Crude Oil Supply
We obtain the crude oil we refine through negotiated term contracts and purchases or exchanges on the spot market. Our term contracts generally have market-related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North America was acquired from various foreign national oil companies, production companies and trading companies.
(mbpd) | 2025 | 2024 | 2023 | |||||||||||||||||
| United States | 1,966 | 1,840 | 1,782 | |||||||||||||||||
| Canada | 599 | 604 | 597 | |||||||||||||||||
| Other international | 222 | 270 | 298 | |||||||||||||||||
| Total | 2,787 | 2,714 | 2,677 | |||||||||||||||||
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Our refineries receive crude oil and other feedstocks and distribute our refined products through a variety of channels, including pipelines, trucks, railcars, ships and barges.
Refined Product Sales
Our refined products are sold to independent retailers, wholesale customers, our brand jobbers and direct dealers. In addition, we sell refined products for export to international customers. As of December 31, 2025, there were 7,882 brand jobber outlets in 40 states, the District of Columbia and Mexico where independent entrepreneurs primarily maintain Marathon-branded outlets. We also have long-term supply contracts for 1,162 direct dealer locations primarily in Southern California, largely under the ARCO® brand. We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers within our market area.
The following table sets forth our refined product sales volumes by product group for each of the last three years.
(mbpd) | 2025(a) | 2024(a) | 2023(a) | ||||||||||||||
| Gasoline | 1,980 | 1,922 | 1,933 | ||||||||||||||
| Distillates | 1,237 | 1,187 | 1,128 | ||||||||||||||
| Propane | 97 | 104 | 90 | ||||||||||||||
| NGLs and petrochemicals | 232 | 231 | 220 | ||||||||||||||
| Heavy fuel oil | 94 | 59 | 57 | ||||||||||||||
| Asphalt | 78 | 82 | 82 | ||||||||||||||
| Total | 3,718 | 3,585 | 3,510 | ||||||||||||||
(a) Refined product sales include volumes marketed directly to end-users and trading/supply volumes such as bulk sales to large unbranded resellers and other downstream companies. Marketed volumes directly to end-users, including branded retail stations, were 2,449 mbpd, 2,429 mbpd and 2,385 mbpd for the years ended December 31, 2025, 2024 and 2023, respectively.
Refined Product Sales Destined for Export
We sell gasoline, distillate, asphalt and NGLs for export, primarily out of our Garyville, Galveston Bay, Anacortes and Los Angeles refineries. The following table sets forth our refined product sales destined for export by product group for the past three years.
(mbpd) | 2025 | 2024 | 2023 | ||||||||||||||
| Gasoline | 114 | 116 | 119 | ||||||||||||||
| Distillates | 195 | 199 | 156 | ||||||||||||||
| Asphalt, NGLs and other | 92 | 87 | 88 | ||||||||||||||
| Total | 401 | 402 | 363 | ||||||||||||||
Gasoline and Distillates
We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel oils, jet fuel, kerosene and diesel) to wholesale customers, branded jobbers, direct dealers and on the spot market. In addition, we sell diesel fuel and gasoline for export to international customers. The demand for gasoline and distillates is seasonal in many of our markets, with demand typically at its highest levels during the summer months.
NGLs and Petrochemicals
We are a producer and marketer of NGLs and petrochemicals. Product availability varies by refinery and includes, among others, propylene, xylene, butane, benzene, toluene and cumene. We market these products domestically to customers in the chemical, agricultural and fuel-blending industries. In addition, we produce fuel-grade coke at our Garyville, Detroit, Galveston Bay and Los Angeles refineries, which is used for power generation and in miscellaneous industrial applications, and anode-grade coke at our Los Angeles and Robinson refineries, which is used to make carbon anodes for the aluminum smelting industry.
Asphalt
We have refinery-based asphalt production capacity of 143 mbpcd, which includes asphalt cements, polymer-modified asphalt, emulsified asphalt, industrial asphalts and roofing flux. We have a broad customer base, including asphalt-paving contractors, resellers, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the domestic and export wholesale markets via rail, barge and vessel.
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Propane
We produce propane at all of our refineries. Propane is primarily used for home heating and cooking, as a feedstock within the petrochemical industry, for grain drying and as a fuel for trucks and other vehicles. Our propane sales are split approximately 80 percent and 20 percent between the home heating market and industrial/petrochemical consumers, respectively.
Heavy Fuel Oil
We produce and market heavy residual fuel oil or related components, including slurry, at all of our refineries. Heavy residual fuel oil is primarily used in the utility and ship bunkering (fuel) industries, though there are other more specialized uses of the product.
Refining & Marketing Joint Venture
We hold a 49.9 percent equity interest in LF Bioenergy, an emerging producer of renewable natural gas (“RNG”) in the U.S. LF Bioenergy has been focused on developing and growing a portfolio of dairy farm-based, low carbon intensity RNG projects. Currently, there are six facilities in operation, with one additional facility under construction that is expected to come online over the next 12 months.
Terminals and Transportation
We transport, store and distribute crude oil, feedstocks and refined products through pipelines, terminals and marine fleets owned by MPLX and third parties in our market areas.
We own a fleet of transport trucks and trailers for the movement of refined products and crude oil. In addition, we maintain a fleet of leased and owned railcars for the movement and storage of refined products.
The locations and detailed information about our Refining & Marketing assets are included under Item 2. Properties and are incorporated herein by reference.
Competition, Market Conditions and Seasonality
The downstream petroleum business is highly competitive, particularly with regard to accessing crude oil and other feedstock supply and the marketing of refined products. We compete with a number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of refined products.
We compete in four distinct markets for the sale of refined products—wholesale, including exports, spot, branded and retail distribution. Our marketing operations compete with numerous other independent marketers, integrated oil companies and high-volume retailers. We compete with companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; companies in the sale of refined products on the spot market; and refiners or marketers in the supply of refined products to refiner-branded independent entrepreneurs. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and retail consumers.
Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations. Our operating results are affected by price changes in crude oil, natural gas and refined products, as well as changes in competitive conditions in the markets we serve. Price differentials between sweet and sour crude oils, ANS, WTI and MEH crude oils and other market structure impacts also affect our operating results.
Demand for gasoline, diesel fuel and asphalt is higher during the spring and summer months than during the winter months in most of our markets, primarily due to seasonal increases in highway traffic and construction. As a result, the operating results for our Refining & Marketing segment for the first and fourth quarters may be lower than for those in the second and third quarters of each calendar year.
Midstream
The Midstream segment primarily includes the operations of MPLX, our sponsored MLP, and certain related operations retained by MPC.
MPLX
MPLX owns and operates a network of crude oil, natural gas and refined product pipelines and has joint ownership interests in crude oil, refined products and other pipelines. MPLX also owns and operates light products terminals, storage assets and maintains a fleet of owned and leased towboats and barges in support of fuels distribution on behalf of MPC. MPLX’s assets also include natural gas gathering systems and natural gas processing and NGL fractionation complexes.
MPC-Retained Midstream Assets and Investments
We own four Jones Act medium range product tankers, three Jones Act 750 Series ATB vessels and have ownership interests in several crude oil and refined products pipeline systems and pipeline companies.
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The locations and detailed information about our Midstream assets are included under Item 2. Properties and are incorporated herein by reference.
Competition, Market Conditions and Seasonality
Our Midstream operations face competition for natural gas gathering, crude oil transportation and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering, transportation and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability, residue gas and NGL market connectivity, the ability to obtain a satisfactory price for products recovered and the fees charged for the services supplied to the customer. Competition for oil supplies is based primarily on the price and scope of services, location of gathering/transportation and storage facilities and connectivity to the best priced markets. Competitive factors affecting our fractionation services include availability of fractionation capacity, proximity to supply and industry marketing centers, the fees charged for fractionation services and operating efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, credit and market connectivity. In addition, certain of our Midstream operations are subject to rate regulation, which affects the rates that our common carrier pipelines can charge for transportation services and the return we obtain from such pipelines.
Our Midstream segment can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns and variations in weather patterns from year to year.
Renewable Diesel
Our Renewable Diesel segment includes a wholly owned facility that processes renewable feedstocks into renewable diesel and renewable joint ventures that produce renewable diesel and renewable feedstocks.
Wholly Owned Renewable Processing Facilities
The Dickinson, North Dakota renewables facility has the capacity to produce 184 million gallons per year of renewable diesel from corn oil, soybean oil, fats and greases. The produced renewable diesel generates federal RINs, 45Z tax credits and LCFS credits when sold in California or similar markets. These instruments are used to help meet our Renewable Fuel Standard and LCFS compliance obligations as a petroleum fuel producer.
We own an aggregation facility in Cincinnati, Ohio and a pre-treatment facility in Beatrice, Nebraska. These facilities supply renewable agricultural feedstocks to our Dickinson and Martinez facilities.
Renewable Diesel Joint Ventures
The Martinez renewable diesel joint venture (the “Martinez Renewables joint venture”) is a partnership structured as a 50/50 joint venture with Neste Corporation to refine renewable feedstocks into renewable diesel. The Martinez Renewables facility, which has the capacity to produce 730 million gallons per year including pretreatment capabilities, reached full capacity in late 2024. The produced renewable diesel generates federal RINs, 45Z tax credits and LCFS credits when sold in California or similar markets. These instruments are used to help meet our Renewable Fuel Standard and LCFS compliance obligations as a petroleum fuel producer.
We formed the Green Bison Soy Processing, LLC (“Green Bison Soy Processing”) joint venture with Archer-Daniels-Midland Company (“ADM”) with ADM owning 75 percent of the joint venture and MPC owning 25 percent. Green Bison Soy Processing’s complex in Spiritwood, North Dakota sources and processes local soybeans and supplies the resulting soybean oil exclusively to MPC and has capacity to produce approximately 600 million pounds of refined soybean oil annually, enough feedstock for approximately 75 million gallons of renewable diesel per year.
Competition, Market Conditions and Seasonality
The renewable diesel business is evolving, particularly with regard to regulatory credits, access to renewable feedstock supply and the marketing of renewable products. We compete with a number of other companies in acquiring various renewable feedstocks for processing and in the distribution and marketing of renewable diesel and renewable naphtha, primarily on the West Coast.
We compete in three distinct markets for the sale of renewable diesel—wholesale, spot and retail distribution. We compete with companies in the sale of renewable diesel to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; companies in the sale of renewable diesel on the spot market; and refiners or marketers in the supply of renewable diesel to refiner-branded independent entrepreneurs. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and retail consumers.
Market conditions in the renewable diesel industry are cyclical and subject to global economic and political events and new and changing governmental regulations. Our operating results are affected by price changes in renewable feedstocks as well as
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changes in competitive conditions in the markets we serve. Price differentials between the various renewable feedstocks also affect our operating results.
Demand for renewable diesel may increase during the spring and summer months due to seasonal increases in agricultural activities. As a result, the operating results for our renewable segment for the first and fourth quarters may be lower than for those in the second and third quarters of each calendar year.
REGULATORY MATTERS
Our operations are subject to numerous laws and regulations, including those relating to the protection of the environment. Such laws and regulations include, among others, the Clean Air Act (“CAA”) with respect to air emissions, the Clean Water Act (“CWA”) with respect to water discharges, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. In addition, many states where we operate have similar laws. New laws are being enacted and regulations are being adopted on a continuing basis, and the costs of compliance with such new laws and regulations are very difficult to estimate until finalized.
For a discussion of environmental capital expenditures and costs of compliance, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Environmental Matters and Compliance Costs. For additional information regarding regulatory risks, see Item 1A. Risk Factors.
Rate Regulation
Some of our existing pipelines are considered interstate common carrier pipelines subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (the “ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and the terms and conditions of service must not be unduly discriminatory. The ICA permits interested persons to challenge newly proposed tariff rates or terms and conditions of service, or any change to tariff rates or terms and conditions of service, and authorizes FERC to suspend the effectiveness of such proposal or change for a period of time to investigate. If, upon completion of an investigation, FERC finds that the new or changed service or rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. An interested person may also challenge existing terms and conditions of service or rates and FERC may order a carrier to change its terms and conditions of service or rates prospectively. Upon an appropriate showing, a shipper may also obtain reparations from a pipeline for damages sustained as a result of rates or terms which FERC deemed were not just and reasonable. Such reparation damages may accrue from the complaint through the final order and during the two years prior to the filing of a complaint.
The EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Our rates for interstate transportation service in effect for the 365-day period ending on the date of the passage of the EPAct 1992 were deemed just and reasonable and therefore are grandfathered. Subsequent changes to those rates are not grandfathered. New rates have since been established after the EPAct 1992 for certain pipelines, and certain of our pipelines have subsequently been approved to charge market-based rates.
FERC permits regulated oil pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. A carrier must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.
Air
GHG Emissions
Certain states and regions have adopted, or are considering, rules regulating GHG emissions. These measures may include state actions to develop statewide or regional programs to report and reduce GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. For example, California has extended its Cap-and-Invest (formerly, Cap-and-Trade) program through 2045. As the emission reduction goals of the program increase, the compliance costs for California refineries may significantly disadvantage in-state refineries as compared to out-of-state refineries depending on multiple factors including the number of allowances granted to in-state refineries. State GHG emission rules may also include low-carbon fuel standards, such as the California program, or a state carbon tax. In all, these state measures could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls and costs to administer any carbon trading or tax programs implemented.
States are increasingly announcing aspirational goals to be net-zero carbon emissions by a certain date through both legislation and executive orders. To date, these states have not provided significant details as to achievement of these goals; however, meeting these aspirations will require a reduction in fossil fuel combustion and/or a mechanism to capture GHGs from the
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atmosphere. As a result, we cannot currently predict the impact of these potential regulations on our liquidity, financial position, or results of operations.
International jurisdictions have adopted or are considering adopting laws related to the disclosure and regulation of GHG emissions. For example, the European Union Emissions Trading System (“ETS”) is a cap-and-trade type program. GHG emissions from maritime transport became subject to the ETS in 2024. These laws could result in increased costs to distribute our products to foreign jurisdictions.
The EPA’s final rule titled “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,” which was published in March 2024, requires MPLX to control and reduce methane emissions within its natural gas gathering and boosting operations and gas processing facilities. In 2025, the EPA extended the compliance deadlines for several provisions in the rule. The rule is consistent with the voluntary methane reduction programs that MPLX has been implementing through its Focus on Methane Program. As a result, although the rule requires MPLX to make additional investments to further reduce methane emissions, we do not believe the rule will have a material impact to our operations.
Other Air Emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions, or aggregate two or more of our facilities into one application for permitting purposes. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements. However, we may be required to incur capital expenditures and may continue to incur capital expenditures in the future for installation of air pollution control equipment and may encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of, new or amended permits, and we may be required to modify certain of our operations which could increase our operating costs.
In February 2024, the EPA lowered the primary annual National Ambient Air Quality Standard (“NAAQS”) for particulate matter (“PM2.5””) from 12.0 µg/m3 to 9.0 µg/m3. Lowering of the NAAQS and subsequent designation as a nonattainment area could result in increased costs associated with, or result in cancellation or delay of, capital projects at our or our customers’ facilities, or could require emission reductions that could result in increased costs to us or our customers. The final rule is under appeal, and on November 24, 2025, the EPA filed a motion indicating the rule had been issued in error and asked the court to vacate the rule. We cannot predict the effects of the various state implementation plan requirements at this time.
In California, the Governing Board for the South Coast Air Quality Management District (“SCAQMD”) adopted Rule 1109.1 in November 2021, which establishes Best Available Retrofit Control Technology (“BARCT”) oxides of nitrogen (“NOx”) and carbon monoxide (“CO”) emission limits for combustion equipment at petroleum refineries. To comply with Rule 1109.1, the Los Angeles Refinery has established a facility mass emission cap, which is being phased in through 2032. To date, the refinery has completed Phase 1 and Phase 2, which has resulted in the refinery achieving over 80 percent of the required NOx emissions reductions. The remaining 20 percent of NOx reductions required under Phase 3 must be completed by 2032. The rule has resulted, and will result, in increased costs to operate and maintain our Los Angeles Refinery.
Water
Our operations are subject to the CWA, the Safe Drinking Water Act (“SWDA”) and comparable state and local requirements. These laws prohibit discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization. We maintain numerous pre-treatment permits and discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. The CWA also regulates filling or discharges to wetlands and other “waters of the United States.” The scope of water bodies and wetlands covered under the definition of “waters of the United States” has evolved through various rulemakings and court decisions. To the extent the federal rule does not apply, an analogous state law may apply.
In addition, we are regulated under OPA-90, which, among other things, requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. OPA-90 also requires the responsible company to pay resulting removal costs and damages and provides for civil penalties and criminal sanctions for violations of its provisions. We operate tank vessels and facilities from which spills of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures plans for all facilities subject to such requirements. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.
As part of our emergency response activities, we have used aqueous film forming foam (“AFFF”) containing per- and polyfluoroalkyl substances (“PFAS”) chemicals as a vapor and fire suppressant. At this time, AFFFs containing PFAS are the most effective foams to prevent and control a flammable petroleum-based liquid fire involving a large storage tank or tank containment area. Fluorine-free firefighting foams are currently under development but have not yet proven to be as effective as AFFFs containing PFAS for all applications.
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In May 2016, the EPA issued lifetime health advisory levels (“HALs”) and health effects support documents for two PFAS substances - perfluorooctanoic acid (“PFOA”) and perfluorooctane sulfonate (“PFOS”). These HALs were updated in June 2022, when the EPA also issued HALs for two additional PFAS substances. In February 2019, the EPA issued a PFAS Action Plan identifying actions it is planning to take to study and regulate various PFAS chemicals. The EPA identified that it would evaluate, among other actions, (1) proposing national drinking water standards for PFOA and PFOS, (2) developing cleanup recommendations for PFOA and PFOS, (3) evaluating the listing of PFOA and PFOS as hazardous substances under CERCLA, and (4) conducting toxicity assessments for other PFAS chemicals. Also, on April 26, 2024, the EPA issued a final rule establishing national drinking water standards for PFOS, PFOA, perfluorohexane sulfonic acid (“PFHxS”), perfluorononanoic acid (“PFNA”), perfluorobutane sulfonic acid (“PFBS”), and hexafluoropropylene oxide dimer acid and its ammonium salt (also known as “GenX”). Congress may also take further action to regulate PFAS. We cannot currently predict the impact of these regulations on our operations.
In addition, many states are actively proposing and adopting legislation and regulations relating to the use of AFFFs containing PFAS. Additionally, many states are using the EPA HALs for PFOS and PFOA and some states are adopting and proposing state-specific drinking water and cleanup standards for various PFAS, including but not limited to PFOS and PFOA. We cannot currently predict the impact of these regulations on our liquidity, financial position, or results of operations.
Solid and Hazardous Waste
We continue to seek methods to minimize the generation of solid and hazardous wastes in our operations. RCRA establishes standards for the management of solid and hazardous wastes. We may incur liability under RCRA, and comparable or more stringent state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous wastes. It is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and disposal requirements. Besides affecting waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of USTs containing regulated substances.
Remediation
We own or operate, or have owned or operated, certain convenience stores and other locations where, during the normal course of operations, releases of refined products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. A portion of these remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable deductibles have been satisfied. We also have ongoing remediation projects at a number of our current and former refinery and midstream locations. For a discussion of environmental capital expenditures and costs of compliance, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Environmental Matters and Compliance Costs.
Claims under CERCLA and similar state acts have been raised with respect to the clean-up of various waste disposal and other sites. CERCLA is intended to facilitate the clean-up of hazardous substances without regard to fault. Potentially responsible parties for each site include present and former owners and operators of, transporters to and generators of the hazardous substances at the site. Liability is strict and can be joint and several. Because of various factors including the difficulty of identifying the responsible parties for any particular site, the complexity of determining the relative liability among them, the uncertainty as to the most desirable remediation techniques and the amount of damages and clean-up costs and the time period during which such costs may be incurred, we are unable to reasonably estimate our ultimate cost of compliance with CERCLA; however, we do not believe such costs will be material to our business, financial condition, results of operations or cash flows. RCRA and similar state laws may also impose liability for removing or remediating releases of hazardous or non-hazardous wastes from impacted properties.
The EPA’s rule designating PFOS and PFOA as hazardous substances under CERCLA Section 102(a) became effective on July 8, 2024. The rule has been challenged in court. In addition, the EPA has received three petitions requesting regulatory action on PFAS under RCRA and in February 2024, proposed two regulations that would add nine PFAS, including PFOA and PFOS, to the list of RCRA hazardous constituents and broaden the definition of hazardous waste applicable to corrective action requirements at hazardous waste treatment, storage, and disposal facilities. We cannot currently predict the impact of potential statutes or regulations on our remediation costs.
Vehicle and Fuel Requirements
Fuel Economy and GHG Emission Standards for Vehicles
The National Highway Traffic Safety Administration (“NHTSA”) establishes corporate average fuel economy (“CAFE”) standards for passenger cars and light trucks. In December 2025, NHTSA proposed to amend the fuel economy standards for light-duty vehicles for model years (“MYs") 2022–2026 and MYs 2027–2031. In its proposal, NHTSA stated that it could not consider battery-powered electric vehicles (“EVs”) when setting the revised standards. NHTSA predicts that the revised standards equate to an industry fleetwide average of roughly 34.5 miles per gallon (“mpg”) for MY 2031.
In 2009, the EPA determined the GHG emissions from motor vehicles contributed to the greenhouse gas pollution that threatens public health and welfare (“Endangerment Finding”). As a result, the EPA began setting GHG emission standards for vehicles,
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which increased in stringency over time and would require a significant increase in electric vehicle production to meet the standards. In February 2026, the EPA rescinded the Endangerment Finding and revoked all existing GHG emission standards for vehicles. The EPA will continue to regulate traditional air pollutants from motor vehicles. The EPA’s rescission of the Endangerment Finding and elimination of the GHG Emission standards has been challenged in court.
In addition, California may establish different, more stringent vehicle standards that could apply in multiple states if granted a Clean Air Act waiver by the EPA. In January 2025, the EPA granted California a waiver for its Advanced Clean Cars II regulation, which bans the sale of internal combustion engine vehicles in California in 2035. Congress, however, disapproved the EPA’s waiver through the Congressional Review Act process, which means the waiver is no longer valid and California cannot enforce its Advanced Clean Cars II program. California has challenged Congress’s disapproval in court.
Renewable Fuels Standards and Low Carbon Fuel Standards
Pursuant to the Energy Policy Act of 2005 and the EISA, Congress established a Renewable Fuel Standard (“RFS”) program that requires annual volumes of renewable fuel be blended into domestic transportation fuel. The statutory volumes apply through calendar year 2022. After calendar year 2022, the statute gives the EPA the authority to set the annual volumes. The EPA has proposed annual volumes for 2026 and 2027 that increase the volume of renewable fuel that must be blended year over year. The EPA is also considering reallocation of small refinery exempted volumes to the non-exempt refineries.
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.
In addition to the federal Renewable Fuel Standards, certain states have, or are considering, promulgation of state renewable or low carbon fuel standards. For example, California has implemented a low carbon fuel standard program that requires a reduction in the carbon intensity of liquid fuel sold for use in the state over time. We incur costs to comply with these state low carbon fuel standard programs, and these costs may increase if the cost of credits increases.
In sum, the RFS has required, and may in the future continue to require, additional capital expenditures or expenses by us to accommodate increased renewable fuels use. We may experience a decrease in demand for refined products due to an increase in combined fleet mileage or due to refined products being replaced by renewable fuels. Demand for our refined products also may decrease as a result of low carbon fuel standard programs or electric vehicle mandates.
Safety Matters
We are subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended (“OSH Act”), as well as comparable state statutes that regulate the protection of the health and safety of workers. We believe that we have conducted our operations in substantial compliance with regulations promulgated pursuant to the OSH Act, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.
We are also subject at regulated facilities to the Occupational Safety and Health Administration’s Process Safety Management and the EPA’s Risk Management Program (“RMP”) requirements, which are intended to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. In 2024, the EPA finalized revisions to its RMP regulation. The revisions include a requirement that refineries with hydrofluoric acid alkylation units perform a safer technologies and alternatives analysis as part of the process hazard analysis and to document the feasibility of inherent safety measures. The application of these regulations can result in increased compliance expenditures. Additionally, three non-governmental organizations have filed a lawsuit asking the court to order the EPA to issue a rule under TSCA that would mitigate, or potentially ban, the use of hydrofluoric acid at petroleum refineries. The Western States Petroleum Association has moved to intervene in the lawsuit.
In general, we expect industry and regulatory safety standards to become more stringent over time, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.
The U.S. Department of Transportation (“DOT”) has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
Security
We have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.
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Tribal Lands
Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. In addition, each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our operations on such lands.
TRADEMARKS, PATENTS AND LICENSES
Our Marathon and ARCO trademarks are material to the conduct of our refining and marketing operations. We currently hold a number of U.S. and foreign patents and have various pending patent applications. Although in the aggregate our patents and licenses are important to us, we do not regard any single patent or license or group of related patents or licenses as critical or essential to our business as a whole. In general, we depend on our technological capabilities and the application of know-how rather than patents and licenses in the conduct of our operations.
HUMAN CAPITAL
We believe our employees are our greatest asset of strength, and our culture reflects the quality of individuals across our workforce. Our collaborative efforts, which include fostering an inclusive environment, providing broad-based development and mentorship opportunities, recognizing and rewarding accomplishments and offering benefits that support the well-being of our employees and their families, contribute to increased engagement and fulfilling careers. Empowering our people and prioritizing accountability are also key components for developing MPC’s high-performing culture, which is critical to achieving our strategic vision.
Employee Profile
As of December 31, 2025, we employed approximately 18,500 people in full-time and part-time roles. Many of these employees provide services to MPLX, for which we are reimbursed in accordance with employee service agreements. Approximately 3,800 of our employees are covered by collective bargaining agreements.
Safety
We are committed to safe operations to protect the health and safety of our employees, contractors and communities. Our commitment to safe operations is reflected in our safety systems design, our well-maintained equipment and by learning from our incidents. Part of our effort to promote safety includes our Operational Excellence Management System, which expands on the RC14001® scope, incorporates a Plan-Do-Check-Act continual improvement cycle, and aligns with ISO 9001, incorporating quality and an increased stakeholder and process focus. Together, these components of our safety management system provide us with a comprehensive approach to managing risks and preventing incidents, illnesses and fatalities. Additionally, our annual cash bonus program includes a broad set of measures tied to safety, environmental stewardship and human capital management.
Talent Management
Our People Strategy holistically addresses the dynamic business environment we operate in. It enables us to be an employer of choice in the face of shifting talent needs and availability. Executing our People Strategy requires that we attract and retain the best talent with the right skills and capabilities when we need them. Attracting and retaining top talent involves presenting employees with the tools for success and providing opportunities for long-term engagement and career advancement. MPC also provides job architecture with defined skills and competencies, along with tools and people processes to identify skill gaps and support career development to help our employees grow. Our Talent Acquisition team consists of three segments: Executive Recruiting, Experienced Recruiting and University Recruiting. The specialization within each group allows us to specifically address MPC’s broad range of current and future talent needs, as well as devote time and attention to candidates during the hiring process. We believe each candidate brings a new perspective to our workforce, and we actively seek candidates with a variety of backgrounds and experience.
We equip our employees at every level with classroom training, online courses and on the job activities that provide the knowledge and skills necessary to perform their daily job functions safely and successfully. Simultaneously, we support our employees with a wide range of career development programs, tools, and key talent processes to help them advance and grow their careers within MPC.
Compensation and Benefits
To ensure we are offering competitive pay packages, we annually benchmark compensation, including base salaries, bonus levels and long-term incentive targets. Our annual bonus program, for which all employees are eligible, is a critical component of our compensation as it rewards employees for MPC’s achievement against preset goals, encouraging employee commitment
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and ownership of results. Employees in our senior leader pay grades, as well as most other leaders, receive long-term incentive awards annually to align their compensation to the interests of MPC shareholders and MPLX unitholders.
We offer comprehensive benefits that are also benchmarked annually, including medical, dental and vision insurance for our employees, their spouses or domestic partners, and their dependents. We also provide retirement programs, including a 401(k) plan and active defined benefit plan, life insurance, family building and support programs, sick and disability benefits, education assistance, as well as support the well-being of our employees and their families through a comprehensive Employee Assistance Program and financial wellness tools. In addition, we encourage our employees to refresh and recharge by providing competitive vacation programs and paid parental leave benefits for birth mothers and nonbirth parents. Further, we award a significant number of college and trade school scholarships to high school senior children of our employees through the Marathon Petroleum Scholars Program. Both full-time and part-time employees are eligible for these benefits.
Inclusion
Inclusion is embedded in our People Strategy, guided by our core values, and supported by a dedicated team of subject matter experts and leadership. Our approach is grounded in our belief that a workplace where employees feel respected, supported and empowered to contribute their best leads to better performance and safer operations. By embedding inclusion and opportunity into the way we work, we strengthen collaboration, fuel innovation and position MPC for long-term success.
We promote inclusivity and respect among our employees. We recognize that when employees feel valued, it shows in their performance. Our employee networks demonstrate this by offering voluntary opportunities for employees to connect with others. Any employee may choose to join any of the seven groups - ADAPT, ARISE, FAMILIA, HONOR, HOPE, PRIDE, and PROMISE. Led by employees with involvement and support from executive sponsors, our networks connect colleagues from across the company and provide opportunities for development, networking, and community involvement.
EXECUTIVE OFFICERS
Following is information about MPC’s executive and corporate officers:
| Name | Age as of February 1, 2026 | Position with MPC | ||||||||||||
| Maryann T. Mannen* | 63 | Chairman, President and Chief Executive Officer | ||||||||||||
| Maria A. Khoury* | 55 | Executive Vice President and Chief Financial Officer | ||||||||||||
| Molly R. Benson* | 59 | Chief Legal Officer and Corporate Secretary | ||||||||||||
| Michael A. Henschen II* | 55 | Executive Vice President Refining | ||||||||||||
| David R. Heppner | 59 | Chief Strategy Officer and Senior Vice President Business Development | ||||||||||||
| Rick D. Hessling* | 59 | Chief Commercial Officer | ||||||||||||
| Fiona C. Laird | 64 | Chief Human Resources Officer and Senior Vice President Communications | ||||||||||||
| Brian K. Partee | 52 | Chief Business Transformation Officer | ||||||||||||
| Ehren D. Powell | 46 | Senior Vice President and Chief Digital Officer | ||||||||||||
| Julian R. Stoll | 57 | Senior Vice President Value Chain Optimization | ||||||||||||
| James R. Wilkins | 59 | Senior Vice President Health, Environment, Safety and Security | ||||||||||||
| Erin M. Brzezinski* | 43 | Vice President and Controller | ||||||||||||
| Kristina A. Kazarian | 43 | Vice President Finance and Investor Relations | ||||||||||||
| Kelly S. Niese | 46 | Vice President Treasury | ||||||||||||
| Gregory S. Floerke* | 62 | Executive Vice President and Chief Operating Officer of MPLX GP LLC | ||||||||||||
| Shawn M. Lyon* | 58 | Senior Vice President Logistics & Storage of MPLX GP LLC | ||||||||||||
* Executive officer. Officers not so designated are corporate officers.
Ms. Mannen was appointed President and Chief Executive Officer, effective August 2024. She was elected Chairman of the Board effective January 2026, having served as a member of the Board since August 2024. Ms. Mannen previously served as President since January 2024, and as Executive Vice President and Chief Financial Officer from January 2021 through December 2023. Ms. Mannen also was elected Chairman of MPLX’s Board of Directors, effective January 2026, having served as President and Chief Executive Officer of MPLX since August 2024, and as a member of MPLX’s Board of Directors since February 2021. Before joining MPC, she was Executive Vice President and Chief Financial Officer of TechnipFMC (a successor to FMC Technologies, Inc.), a leading global engineering services and energy technology company, beginning in 2017, having previously served as Executive Vice President and Chief Financial Officer of FMC Technologies, Inc. since 2014, as Senior Vice President and Chief Financial Officer since 2011, and in various positions of increasing responsibility with FMC Technologies, Inc. since 1986. Ms. Mannen serves as chairman of the American Petroleum Institute (API), on the executive committee of American Fuel and Petrochemical Manufacturers (AFPM) and the executive committee of the Ohio Business Roundtable, and is
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a member of The Business Council. She also serves as secretary of the Cynthia Woods Mitchell Pavilion board of directors and is a member of its executive and finance committees.
Ms. Khoury was appointed Executive Vice President and Chief Financial Officer, effective January 19, 2026. She also has served as a member of MPLX’s Board since January 19, 2026. Before joining MPC, Ms. Khoury was Vice President, Group CFO Biotechnology, Life Sciences for Danaher Corporation, a global science and technology innovator, since 2021. Ms. Khoury was CFO Cytiva, Danaher Life Sciences Vice President Finance and IT, from 2020 to 2021, and CFO GE Life Sciences, GE Healthcare from 2017 through its acquisition by Danaher in 2019. From 2010 to 2017, Ms. Khoury served in financial leadership positions within GE Oil & Gas, including as CFO of GE’s Oil & Gas Drilling & Surface division. From 1999 to 2010, she held domestic and international positions of increasing responsibility in financial planning and analysis and treasury for GE Corporate and GE Capital Treasury. Before joining GE in 1999, Ms. Khoury spent five years with Cargill, Inc., where she began her finance career.
Ms. Benson was appointed Chief Legal Officer and Corporate Secretary, effective January 2024, having previously served as Vice President, Chief Securities, Governance & Compliance Officer and Corporate Secretary since 2018, and as Vice President, Chief Compliance Officer and Corporate Secretary since 2016. Prior to her 2016 appointment, Ms. Benson served as Assistant General Counsel Corporate and Finance beginning in 2012, and as Group Counsel Corporate and Finance beginning in 2011.
Ms. Laird was appointed Chief Human Resources Officer and Senior Vice President Communications, effective February 2021, having previously served as Chief Human Resources Officer since October 2018. Prior to her 2018 appointment, she served as Chief Human Resources Officer at Andeavor beginning in February 2018. Before joining Andeavor, Ms. Laird was Chief Human Resources and Communications Officer for Newell Brands, a global consumer goods company, beginning in 2016 and Executive Vice President Human Resources for Unilever, a global consumer goods company, beginning in 2011.
Mr. Henschen was appointed Executive Vice President Refining, effective June 2025, having previously served as Senior Vice President Refining since October 2024. Prior to his 2024 appointment, he served as Vice President Refining beginning in 2020, as Director Refining, Reliability and Engineering beginning in 2017, as maintenance manager for the Detroit refinery and then the Galveston Bay refinery beginning in 2011, and as a refining planner beginning in 2004. Mr. Henschen serves on the executive board of directors for the Louisiana Mid-Continent Oil and Gas Association (LMOGA).
Mr. Heppner was appointed Chief Strategy Officer and Senior Vice President Business Development, effective March 2024, having previously served as Senior Vice President Strategy and Business Development since February 2021. Prior to his 2021 appointment, he served as Vice President Commercial and Business Development beginning in 2018, as Senior Vice President of Engineering Services and Corporate Support of Speedway LLC beginning in 2014, and as Director Wholesale Marketing beginning in 2010.
Mr. Hessling was appointed Chief Commercial Officer, effective January 2024, having previously served as Senior Vice President Global Feedstocks since February 2021. Prior to his 2021 appointment, he served as Senior Vice President Crude Oil Supply and Logistics beginning in 2018, as Manager Crude Oil & Natural Gas Supply and Trading beginning in 2014, and as Crude Oil Logistics & Analysis Manager beginning in 2011.
Mr. Partee was appointed Chief Business Transformation Officer, effective April 2025, having previously served as Chief Global Optimization Officer since January 2024. Prior to his 2024 appointment, he served as Senior Vice President Global Clean Products beginning in February 2021, as Senior Vice President Marketing beginning in October 2018, as Vice President Business Development beginning in February 2018, as Director Business Development beginning in 2017, as Manager Crude Oil Logistics beginning in 2014, and as Vice President Business Development and Franchise at Speedway beginning in 2012.
Mr. Powell was appointed Senior Vice President and Chief Digital Officer, effective July 2020. Before joining MPC, he was Vice President and Chief Information Officer (“CIO”) at GE Healthcare, a segment of General Electric Company (“GE”) that provides medical technologies and services, beginning in 2018, having previously served as Senior Vice President and CIO Services at GE, a multinational conglomerate, beginning in 2017, as CIO Power Services at GE Power beginning in 2014, and in various positions of increasing responsibility with GE and its subsidiaries since 2000.
Mr. Stoll was appointed Senior Vice President Value Chain Optimization, effective March 2025. Before joining MPC, he was Executive Vice President and Chief Operating Officer at VARO Energy, a diversified energy company in Switzerland, beginning in January 2022, having previously served as Chief Operating Officer since March 2020. Previously, Mr. Stoll spent nearly 30 years at Phillips 66, an integrated downstream energy provider, and its predecessor ConocoPhillips, serving in roles of increasing responsibility including as Vice President, Refining Operations and as Vice President, Business Transformation.
Mr. Wilkins was appointed Senior Vice President Health, Environment, Safety and Security, effective February 2021. Prior to this appointment, he served as Vice President Environment, Safety and Security beginning in 2018, as Director Environment, Safety, Security and Product Quality beginning in 2016, and as Director Refining Environmental, Safety, Security and Process Safety Management beginning in 2013.
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Ms. Brzezinski was appointed Vice President and Controller, effective January 2024. Prior to this appointment, she served as Assistant Controller, Technical Accounting, since August 2021, having previously served as Manager, Accounting, since 2019. Before joining MPC, Ms. Brzezinski was Director, Assurance and Audit Services, at PricewaterhouseCoopers LLP, a professional services and accounting firm, beginning in 2018, and Senior Manager beginning in 2013. She was Manager, Technical Accounting, at Cooper Tire & Rubber Company, an automotive tire manufacturer, from 2011 to 2013. Previously, Ms. Brzezinski served in positions of increasing responsibility with PricewaterhouseCoopers LLP beginning in 2004.
Ms. Kazarian was appointed Vice President Finance and Investor Relations, effective January 2023, having previously served as Vice President Investor Relations since 2018. Before joining MPC, she was Managing Director and head of the MLP, Midstream and Refining Equity Research teams at Credit Suisse, a global investment bank and financial services company, beginning in 2017. Previously, Ms. Kazarian was Managing Director of MLP, Midstream and Natural Gas Equity Research at Deutsche Bank, a global investment bank and financial services company, beginning in 2014, and an analyst specializing on various energy industry subsectors with Fidelity Management & Research Company, a privately held investment manager, beginning in 2005.
Ms. Niese was appointed Vice President Treasury, effective January 2023. Prior to this appointment, she served as Assistant Treasurer beginning in February 2017, as Corporate Finance Manager beginning in October 2014, and as Brand Coordinating Manager beginning in 2011, having previously served in various analytical roles within Crude Supply, Terminals, Transportation and Rail and Internal Audit since joining MPC in 2003.
Mr. Floerke was appointed Executive Vice President and Chief Operating Officer of MPLX, effective February 2021, having previously served as Executive Vice President and Chief Operating Officer, Gathering and Processing, Trucks and Rail, since August 2020. Prior to his 2020 appointment, he served as Executive Vice President Gathering and Processing beginning in 2018, as Executive Vice President and Chief Operating Officer, MarkWest Operations, beginning in July 2017, and as Executive Vice President and Chief Commercial Officer, MarkWest Assets, beginning in December 2015 upon our acquisition of MarkWest Energy Partners, L.P. Before joining MPLX, Mr. Floerke was Executive Vice President and Chief Commercial Officer at MarkWest beginning in 2015, and Senior Vice President, Northeast Region, at MarkWest beginning in 2013. Previously, he held senior management positions at Access Midstream Partners, L.P. from 2011 until 2013. Mr. Floerke is a member of the board of directors of TransTech Group, LLC.
Mr. Lyon was appointed Senior Vice President Logistics and Storage of MPLX, effective September 2022, having previously served as Vice President Operations and President Marathon Pipe Line LLC since 2018. Prior to his 2018 appointment, he served as Vice President of Operations for Marathon Pipe Line LLC beginning in 2011. Previously, Mr. Lyon served in various roles of increasing responsibility with MPC since 1989, including as Manager Marketing and Transportation Engineering beginning in 2010, and as District Manager Transport and Rail beginning in 2008. He served as board chair for Liquid Energy Pipeline Association in 2023 and chairs the board of the Louisiana Offshore Oil Port (LOOP).
AVAILABLE INFORMATION
General information about MPC, including our Corporate Governance Principles, our Code of Business Conduct and our Code of Ethics for Senior Financial Officers, can be found on our website at www.marathonpetroleum.com/Investors/Corporate-Governance/. We would post on our website any amendments to, or waivers from, either of our codes requiring disclosure under applicable rules within four business days following any such amendment or waiver. Charters for the Audit Committee, Compensation and Organization Development Committee, Corporate Governance and Nominating Committee and Sustainability and Public Policy Committee are also available on our website at www.marathonpetroleum.com/About/Board-of-Directors/.
We use our website, www.marathonpetroleum.com, as a channel for routine distribution of important information, including news releases, analyst presentations, financial information and market data. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC, or on the SEC’s website. The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.
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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:
•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 efficiency improvements 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 incidents adversely 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 persistent threats and nation-state actors, state-sponsored actors, or employee error or malfeasance. Cybersecurity threat actors also may attempt to exploit vulnerabilities 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 better able 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 prolonged interruption, 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 prolonged disruption 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 alleged violations 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 severely disrupts 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, alleging damages 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 violate deceptive 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 damages against 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 defending litigation 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 alleged damages 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 allege damages 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 successfully defend 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 stoppages disrupting 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.
Item 1B. Unresolved Staff Comments
None
Item 1C. Cybersecurity
Risk Management and Strategy
We have processes in place designed to protect our information systems, data, assets, infrastructure, and computing environments from cybersecurity threats and risks while maintaining confidentiality, integrity, and availability. These enterprise-wide processes are based upon policies, practices, and standards that guide us on identifying, assessing, and managing material risks from cybersecurity threats and include, but are not limited to:
•placing security limits on physical and network access to our information technology (“IT”) and operating technology (“OT”) systems;
•employing internal IT and OT controls designed to detect cybersecurity threats by collecting and analyzing data in our centralized cybersecurity operations center;
•utilizing layers of defensive methodologies designed to facilitate cyber resilience, minimize attack surfaces, and provide flexibility and scalability in our ability to address cybersecurity risks and threats;
•providing cybersecurity threat and awareness training to employees and contractors;
•limiting remote network access to our IT and OT network environments; and
•assessing our cybersecurity resiliency through various methods, including penetration testing, tabletop exercises with varying scenarios and participants ranging from individuals on our operations teams to executive leadership, and analyzing our corporate cybersecurity incident response plan.
We apply an enterprise risk management (“ERM”) methodology as established and led by our executive leadership team and overseen by our Board to identify, assess, and manage enterprise-level risks. Our cybersecurity risk program directly integrates and is intended to align with our governing ERM program.
We engage with external resources to contribute to and provide independent evaluation of our cybersecurity practices, including a periodic assessment of our cybersecurity program that is performed by a third party. Our cybersecurity leadership and operational teams monitor cybersecurity threat intelligence and applicable cybersecurity regulatory requirements in a variety of ways, including by communicating with federal agencies, trade associations, service providers, and other miscellaneous third-party resources. Our management team, through consultation with our Senior Vice President and Chief Digital Officer (“CDO”), Vice President and Chief Information Security Officer (“CISO”), and the Audit Committee of our Board, use the information gathered from these sources to inform long-term cybersecurity investments and strategies which seek to identify cybersecurity threats and protect against, detect, respond to, and recover from cybersecurity incidents.
The information systems, data, assets, infrastructure, and computing environments of our third-party service providers are also at risk of cybersecurity incidents. We manage third-party service provider cybersecurity risks through contract management, evaluation of applicable security control assessments, and third-party risk assessment processes.
As of February 26, 2026, we do not believe that any risks from cybersecurity threats, including as a result of past cybersecurity incidents, have had, or are reasonably likely to have, a material adverse effect on the company, including our business strategy, results of operations, or financial condition. However, there can be no assurance that our cybersecurity processes will prevent or mitigate cybersecurity incidents or threats and that efforts will always be successful. It is possible that cybersecurity incidents may occur and could have a material adverse effect on our business strategy, results of operations, or financial condition. See “Business and Operational Risks--We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers” in Item 1A. Risk Factors of this Annual Report on Form 10-K.
Governance
Our full Board of Directors oversees enterprise-level risks and in conjunction with the Audit Committee of our Board oversees risks from cybersecurity threats as informed through the ERM program. Our CDO and CISO are standing members of the ERM committee, comprised of members of senior management, and as part of the committee, report on and evaluate cybersecurity threats and risk management efforts, as communicated to them by way of their direct reports and the larger cybersecurity team. The CDO and CISO are responsible for assessing and managing risks from cybersecurity threats. The CDO and CISO provide
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regular cybersecurity briefings to the Board of Directors including the Audit Committee, with a minimum of two briefings per year and additional briefings as needed. The Audit Committee also has direct access to the CDO and CISO and their management teams for other updates on cybersecurity and information security strategy throughout the year. Additionally, the CDO and CISO, from time to time, meet with members of management to discuss cybersecurity risks, strategy and threats.
Our CISO is responsible for implementing the cybersecurity program which is comprised of Cybersecurity GRC (Governance, Risk & Compliance), Cybersecurity Architecture, Engineering & Operations, and a Cyber Fusion Center that includes Threat Intelligence, Vulnerability Management, & Incident Response. Our CISO has more than 30 years of experience in the oil and gas industry and has held various leadership and strategic roles related to information security and related technology, including collectively serving as a chief information security officer for seven years at two publicly traded companies. Our CISO also holds an Executive Master in Cybersecurity degree and a Master of Computer Science degree.
Our CISO works at the direction of the CDO, who has more than 20 years of executive IT leadership experience and leads the company’s Digital and Information Technology functions that seek to provide innovative, secure, and reliable technology products and services to MPC and its customers. Prior to joining MPC in 2021, our CDO was employed by GE and its subsidiary companies for over 20 years, holding several executive IT leadership roles with increasing responsibility. He was then named Senior Vice President and Chief Information Officer of Services for parent company GE in 2017 and was later named the Vice President and Chief Information Officer of GE Healthcare. Our CDO holds a Bachelor’s degree in Business Administration, Management and Information Systems.
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Item 2. Properties
We believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. See the following sections for details of our assets by segment.
REFINING & MARKETING
The table below sets forth the location and crude oil refining capacity for each of our refineries as of December 31, 2025. Refining throughput can exceed crude oil refining capacity due to the processing of other charge and blendstocks in addition to crude oil and the timing of planned turnaround and major maintenance activity.
| Refinery | Crude Oil Refining Capacity (mbpcd) | |||||||
| Gulf Coast Region | ||||||||
| Galveston Bay, Texas City, Texas | 631 | |||||||
| Garyville, Louisiana | 617 | |||||||
| Subtotal Gulf Coast region | 1,248 | |||||||
| Mid-Continent Region | ||||||||
| Catlettsburg, Kentucky | 307 | |||||||
| Robinson, Illinois | 253 | |||||||
| Detroit, Michigan | 146 | |||||||
| El Paso, Texas | 133 | |||||||
| St. Paul Park, Minnesota | 105 | |||||||
| Canton, Ohio | 100 | |||||||
| Mandan, North Dakota | 72 | |||||||
| Salt Lake City, Utah | 70 | |||||||
| Subtotal Mid-Continent region | 1,186 | |||||||
| West Coast Region | ||||||||
| Los Angeles, California | 365 | |||||||
| Anacortes, Washington | 119 | |||||||
| Kenai, Alaska | 68 | |||||||
| Subtotal West Coast region | 552 | |||||||
| Total | 2,986 | |||||||
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The following table sets forth the approximate number of locations where jobbers maintain branded outlets, marketing fuels mainly under the Marathon and ARCO brands as well as Shell, Mobil, Tesoro and other brands, as of December 31, 2025.
| Location | Number of Branded Outlets | |||||||
| Alabama | 417 | |||||||
| Alaska | 54 | |||||||
| Arizona | 88 | |||||||
| California | 101 | |||||||
| Colorado | 12 | |||||||
| Connecticut | 1 | |||||||
| District of Columbia | 2 | |||||||
| Florida | 626 | |||||||
| Georgia | 530 | |||||||
| Idaho | 107 | |||||||
| Illinois | 178 | |||||||
| Indiana | 682 | |||||||
| Iowa | 15 | |||||||
| Kentucky | 531 | |||||||
| Louisiana | 82 | |||||||
| Maryland | 67 | |||||||
| Massachusetts | 1 | |||||||
| Mexico | 283 | |||||||
| Michigan | 710 | |||||||
| Minnesota | 334 | |||||||
| Mississippi | 159 | |||||||
| Missouri | 12 | |||||||
| Nevada | 19 | |||||||
| New Jersey | 9 | |||||||
| New Mexico | 45 | |||||||
| New York | 61 | |||||||
| North Carolina | 286 | |||||||
| North Dakota | 126 | |||||||
| Ohio | 944 | |||||||
| Oregon | 59 | |||||||
| Pennsylvania | 97 | |||||||
| Rhode Island | 3 | |||||||
| South Carolina | 114 | |||||||
| South Dakota | 31 | |||||||
| Tennessee | 401 | |||||||
| Texas | 14 | |||||||
| Utah | 93 | |||||||
| Virginia | 262 | |||||||
| Washington | 96 | |||||||
| West Virginia | 155 | |||||||
| Wisconsin | 72 | |||||||
| Wyoming | 3 | |||||||
| Total | 7,882 | |||||||
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The Refining & Marketing segment sells transportation fuels through long-term fuel supply contracts to direct dealer locations, primarily under the ARCO brand. The following table sets forth the number of direct dealer locations by state as of December 31, 2025.
| Location | Number of Locations | |||||||
| Arizona | 69 | |||||||
| California | 974 | |||||||
| Nevada | 117 | |||||||
| New Mexico | 1 | |||||||
| Oregon | 1 | |||||||
| Total | 1,162 | |||||||
The following table sets forth details about our Refining & Marketing owned and operated terminals as of December 31, 2025. See the Midstream - MPLX section for information with respect to MPLX owned and operated terminals.
| Owned and Operated Terminals | Number of Terminals | Tank Storage Capacity (mbbls) | ||||||||||||
| Light Products Terminals: | ||||||||||||||
| Alaska | 1 | 242 | ||||||||||||
| New York | 1 | 334 | ||||||||||||
| Subtotal light products terminals | 2 | 576 | ||||||||||||
| Asphalt Terminals: | ||||||||||||||
| Florida | 1 | 263 | ||||||||||||
| Indiana | 1 | 122 | ||||||||||||
| Kentucky | 4 | 537 | ||||||||||||
| Louisiana | 1 | 54 | ||||||||||||
| Michigan | 1 | 12 | ||||||||||||
| New York | 1 | 417 | ||||||||||||
| Ohio | 4 | 2,207 | ||||||||||||
| Pennsylvania | 1 | 451 | ||||||||||||
| Tennessee | 2 | 480 | ||||||||||||
| Subtotal asphalt terminals | 16 | 4,543 | ||||||||||||
| Total owned and operated terminals | 18 | 5,119 | ||||||||||||
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MIDSTREAM - MPLX
The following table sets forth certain information relating to MPLX’s crude oil and refined products pipeline systems and storage assets as of December 31, 2025.
| Pipeline System or Storage Asset | Diameter (inches) | Length (miles) | Capacity | ||||||||||||||||||||
Total crude oil pipeline systems(a)(b) | 2" - 42" | 5,259 | Various | ||||||||||||||||||||
Total refined products pipeline systems(a)(b)(c) | 4" - 36" | 3,787 | Various | ||||||||||||||||||||
Barge Docks (mbpd) | 5,104 | ||||||||||||||||||||||
Storage assets: (mbbls) | |||||||||||||||||||||||
Refining Logistics(d) | 93,643 | ||||||||||||||||||||||
| Tank Farms | 35,456 | ||||||||||||||||||||||
| Caverns | 3,632 | ||||||||||||||||||||||
(a) Includes approximately 16 miles of crude oil pipeline and 2 miles of refined product pipeline leased from third parties.
(b) Includes approximately 1,168 miles of inactive crude oil pipeline and 197 miles of inactive refined product pipeline.
(c) Includes approximately 87 miles and 17 miles of refined product pipelines in which MPLX has partial ownership of 65 percent and 50 percent, respectively.
(d) Refining logistics assets primarily include tankage. MPLX owns refining logistics assets at the Martinez Renewables joint venture facility with 5,914 mbbls of storage capacity associated with the facility and has entered into terminalling and storage service agreements with the joint venture and its partners to provide services for the facility.
The following table sets forth information regarding the crude oil and refined product pipeline systems which MPLX has an interest in through ownership of its equity method investments as of December 31, 2025.
Diameter (inches) | Length (miles) | Ownership Percentage | ||||||||||||||||||
| Crude Oil Systems: | ||||||||||||||||||||
MarEn Bakken Company LLC(a) | 30" | 1,916 | 25 | % | ||||||||||||||||
| Minnesota Pipe Line Company LLC | 16" - 24" | 975 | 17 | % | ||||||||||||||||
W2W Holdings LLC(b) | 24" - 36" | 652 | 50 | % | ||||||||||||||||
| Illinois Extension Pipeline Company LLC | 24" | 168 | 35 | % | ||||||||||||||||
| Andeavor Logistics Rio Pipeline LLC | 12" | 119 | 67 | % | ||||||||||||||||
| LOCAP LLC | 48" | 57 | 59 | % | ||||||||||||||||
| LOOP LLC | 48" | 48 | 41 | % | ||||||||||||||||
| Refined Product Systems: | ||||||||||||||||||||
| Explorer Pipeline Company | 10" - 28" | 1,872 | 25 | % | ||||||||||||||||
(a) The investment in MarEn Bakken Company LLC includes MPLX’s 9.19 percent indirect interest in a joint venture that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively referred to as the “Bakken Pipeline system”).
(b) The investment in W2W Holdings LLC includes MPLX’s 16 percent indirect interest in Wink to Webster Pipeline LLC.
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The following table sets forth details about MPLX owned and operated terminals as of December 31, 2025. Additionally, MPLX has partial ownership interest in one terminal.
| Owned and Operated Terminals | Number of Terminals | Tank Storage Capacity (mbbls) | ||||||||||||
| Refined Products Terminals: | ||||||||||||||
| Alabama | 2 | 443 | ||||||||||||
| Alaska | 3 | 1,536 | ||||||||||||
| California | 8 | 3,472 | ||||||||||||
| Florida | 3 | 2,265 | ||||||||||||
| Georgia | 4 | 952 | ||||||||||||
| Idaho | 3 | 1,020 | ||||||||||||
| Illinois | 2 | 562 | ||||||||||||
| Indiana | 7 | 3,689 | ||||||||||||
| Kentucky | 6 | 2,606 | ||||||||||||
| Louisiana | 2 | 5,469 | ||||||||||||
| Michigan | 8 | 2,440 | ||||||||||||
| Minnesota | 1 | 13 | ||||||||||||
| New Mexico | 2 | 467 | ||||||||||||
| North Carolina | 3 | 1,343 | ||||||||||||
| North Dakota | 1 | — | ||||||||||||
| Ohio | 12 | 3,132 | ||||||||||||
| Pennsylvania | 1 | 390 | ||||||||||||
| South Carolina | 1 | 371 | ||||||||||||
| Tennessee | 4 | 1,148 | ||||||||||||
| Texas | 1 | 76 | ||||||||||||
| Utah | 1 | 41 | ||||||||||||
| Washington | 4 | 920 | ||||||||||||
| West Virginia | 2 | 1,564 | ||||||||||||
| Subtotal light products terminals | 81 | 33,919 | ||||||||||||
| Asphalt Terminals | ||||||||||||||
| Arizona | 3 | 558 | ||||||||||||
| Minnesota | 1 | — | ||||||||||||
Nevada(a) | 1 | 274 | ||||||||||||
| New Mexico | 1 | 36 | ||||||||||||
| Texas | 1 | 206 | ||||||||||||
| Subtotal asphalt terminals | 7 | 1,074 | ||||||||||||
| Total owned and operated terminals | 88 | 34,993 | ||||||||||||
(a) MPLX accounts for this terminal as an equity method investment.
The following table sets forth details about MPLX barges and towboats as of December 31, 2025.
| Class of Equipment | Number in Class | Capacity (mbbls) | ||||||||||||
| Inland tank barges | 320 | 8,655 | ||||||||||||
| Inland towboats | 30 | N/A | ||||||||||||
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The following tables set forth certain information relating to MPLX’s consolidated and operated joint venture gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines as of and for the year ended December 31, 2025.
| Gas Processing Complexes | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput (MMcf/d)(a) | Utilization of Design Capacity(a) | |||||||||||||||||
| Marcellus Operations | 6,520 | 6,123 | 94 | % | ||||||||||||||||
| Utica Operations | 1,325 | 961 | 73 | % | ||||||||||||||||
Southwest Operations(b)(c) | 2,745 | 1,904 | 69 | % | ||||||||||||||||
| Southern Appalachia Operations | 425 | 191 | 45 | % | ||||||||||||||||
Bakken Operations(d) | 185 | 159 | 86 | % | ||||||||||||||||
| Total | 11,200 | 9,338 | 83 | % | ||||||||||||||||
(a) Natural gas throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(b) The capacity presented above includes MPLX’s proportionate share of Centrahoma Processing LLC’s processing capacity of 550 MMcf/d, as MPLX owns a non-operating 40 percent interest in this joint venture. Actual throughput of 99 MMcf/d representing MPLX’s share of processed volumes is also included and used to compute the utilization presented above.
(c) The amounts presented above exclude Northwind Delaware Holdings LLC (“Northwind Midstream”) design throughput capacity and treated volumes.
(d) Includes volumes processed at third-party facilities in the Bakken.
| Fractionation Facilities | Design Throughput Capacity (mbpd) | NGL Throughput (mbpd)(a) | Utilization of Design Capacity(a) | |||||||||||||||||
| Marcellus Operations | 413 | 343 | 83 | % | ||||||||||||||||
Utica Operations(b) | — | — | — | % | ||||||||||||||||
| Southern Appalachia Operations | 24 | 11 | 46 | % | ||||||||||||||||
| Bakken Operations | 33 | 14 | 42 | % | ||||||||||||||||
| Total | 470 | 368 | 78 | % | ||||||||||||||||
(a) NGL throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(b) MPLX operates a condensate stabilization facility with a capacity of 23 mbpd and 179 thousand barrels of condensate storage. Actual NGL throughput at this facility was 15 mbpd for the year ended December 31, 2025.
De-ethanization Facilities | Design Throughput Capacity (mbpd) | NGL Throughput (mbpd)(a) | Utilization of Design Capacity(a) | |||||||||||||||||
| Marcellus Operations | 309 | 267 | 86 | % | ||||||||||||||||
| Utica Operations | 40 | 21 | 53 | % | ||||||||||||||||
| Total | 349 | 288 | 83 | % | ||||||||||||||||
(a) NGL throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
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| Natural Gas Gathering Systems | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput (MMcf/d)(a) | Utilization of Design Capacity(a) | |||||||||||||||||
| Marcellus Operations | 1,823 | 1,526 | 89 | % | ||||||||||||||||
| Utica Operations | 3,923 | 2,672 | 68 | % | ||||||||||||||||
Southwest Operations(b) | 3,445 | 1,826 | 56 | % | ||||||||||||||||
| Bakken Operations | 239 | 160 | 67 | % | ||||||||||||||||
| Total | 9,430 | 6,184 | 68 | % | ||||||||||||||||
(a) Natural gas throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
The following table sets forth certain information relating to MPLX’s NGL pipelines as of December 31, 2025.
| NGL Pipelines | Diameter (inches) | Length (miles) | ||||||||||||
| Marcellus Operations | 6"- 20" | 442 | ||||||||||||
| Utica Operations | 4" - 20" | 185 | ||||||||||||
| Southern Appalachia Operations | 6" - 8" | 140 | ||||||||||||
Southwest Operations(a) | 4" - 20" | 530 | ||||||||||||
| Bakken Operations | 6" - 12" | 104 | ||||||||||||
| Total | 1,401 | |||||||||||||
(a) Includes the BANGL Pipeline system, which also owns a 50 percent undivided joint interest in a 323 mile NGL pipeline.
In addition to the MPLX-operated equity method investments included in the above tables, MPLX also has ownership interests in natural gas and NGL pipeline systems through the following entities:
Diameter (inches) | Length (miles) | Ownership Percentage | ||||||||||||||||||
| Natural Gas Pipelines: | ||||||||||||||||||||
Delaware Basin Residue, LLC(a) | 10" - 42" | 298 | 10 | % | ||||||||||||||||
MXP Parent, LLC(b) | 36" - 42" | 580 | 10 | % | ||||||||||||||||
WPC Parent, LLC(c) | 36" - 42" | 541 | 30 | % | ||||||||||||||||
| NGL Pipelines: | ||||||||||||||||||||
| Panola Pipeline Company, LLC | 8" - 20" | 253 | 15 | % | ||||||||||||||||
(a) Includes Agua Blanca Pipeline and Carlsbad Gateway Pipeline.
(b) Includes Matterhorn Express Pipeline.
(c) Includes MPLX’s indirect interest in Whistler Pipeline as well as its 70 percent indirect ownership in the ADCC Pipeline lateral. Also includes MPLX’s 50 percent indirect interest in Waha Gas Storage, which primarily owns natural gas storage facilities.
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MIDSTREAM - MPC-RETAINED ASSETS AND INVESTMENTS
The following table sets forth certain information relating to our crude oil and refined products pipeline systems not owned by MPLX.
As of December 31, 2025, we had partial ownership interests in the following pipeline companies.
| Pipeline Company | Diameter (inches) | Length (miles) | Ownership Interest | Operated by MPL | |||||||||||||||||||||||||
| Crude oil pipeline companies: | |||||||||||||||||||||||||||||
| Capline Pipeline Company LLC | 40” | 644 | 33 | % | Yes | ||||||||||||||||||||||||
| Gray Oak Pipeline, LLC | 8” - 30” | 845 | 25 | % | No | ||||||||||||||||||||||||
LOOP(a) | 48” | 48 | 10 | % | No | ||||||||||||||||||||||||
| Total | 1,489 | ||||||||||||||||||||||||||||
| Refined products pipeline companies: | |||||||||||||||||||||||||||||
| Ascension Pipeline Company LLC | 12” | 34 | 50 | % | No | ||||||||||||||||||||||||
Centennial Pipeline LLC(b) | 24” - 26” | 793 | 50 | % | Yes | ||||||||||||||||||||||||
| Muskegon Pipeline LLC | 10” - 12” | 170 | 60 | % | Yes | ||||||||||||||||||||||||
| Wolverine Pipe Line Company | 6” - 18” | 798 | 6 | % | No | ||||||||||||||||||||||||
| Total | 1,795 | ||||||||||||||||||||||||||||
(a) Represents interest retained by MPC and excludes MPLX’s 41 percent ownership interest in LOOP. Pipeline mileage is excluded from total as it is included with MPLX assets.
(b) All system pipeline miles are inactive.
The following table sets forth details about our ocean vessels as of December 31, 2025.
| Class of Equipment | Number in Class | Capacity (mbbls) | ||||||||||||
| Jones Act medium range product tankers | 4 | 1,320 | ||||||||||||
| Jones Act 750 Series ATB vessels | 3 | 990 | ||||||||||||
RENEWABLE DIESEL
Our Dickinson, North Dakota, renewables facility has the capacity to produce 184 million gallons per year of renewable diesel from corn oil, soybean oil, fats and greases. The Martinez, California renewable diesel facility has the capacity to produce 730 million gallons per year.
Our Green Bison Soy Processing, LLC joint venture with ADM includes a facility in Spiritwood, North Dakota, which has capacity to produce approximately 600 million pounds of refined soybean oil annually, enough feedstock for approximately 75 million gallons of renewable diesel per year.
We own a feedstock aggregation facility in Cincinnati, Ohio and a pre-treatment facility in Beatrice, Nebraska. These facilities supply renewable agricultural feedstocks to our Dickinson and Martinez facilities.
Item 3. Legal Proceedings
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. See “Climate Change Litigation,” “Tesoro High Plains Pipeline,” and “Dakota Access Pipeline” of Note 27 in Item 8. Financial Statements and Supplementary Data for additional information regarding Legal Proceedings and other regulatory matters.
ENVIRONMENTAL ENFORCEMENT MATTERS
Item 103 of Regulation S-K promulgated by the SEC requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions, unless we reasonably believe that the matter will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than a specified threshold. We use a threshold of $1 million for this purpose.
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In March 2022, the State of Illinois brought an action in Madison County Circuit Court in Illinois against Marathon Pipe Line LLC, an indirect wholly owned subsidiary of MPLX, asserting various violations and demanding a permanent injunction and civil penalties in connection with a release of crude oil on the Wood River to Patoka 22-inch line near Edwardsville, Illinois. In September 2023, the U.S. Department of Justice and the EPA confirmed they will be pursuing federal enforcement for alleged Clean Water Act violations arising from this incident as well as three pipeline incidents in Illinois and Indiana in 2018, 2020 and 2021. We cannot currently estimate the timing of the resolution of this matter, but do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.
On December 18, 2023, the EPA Region 6 issued a Notice of Violation and Opportunity to Confer alleging violations of the National Emission Standard for Benzene Waste Operations at 40 C.F.R. Part 61, Subpart FF (“BWON”) and of the New Source Performance Standards for Volatile Organic Compounds from Petroleum Wastewater Systems at 40 C.F.R. Part 60, Subpart QQQ (“NSPS QQQ”) at our Garyville refinery. On January 10, 2024, the EPA Region 5 issued a Finding of Violation alleging violations of BWON and NSPS QQQ at our St. Paul Park refinery. In addition, the EPA has conducted a compliance inspection at our Anacortes refinery. In February 2024, the EPA published an enforcement alert noting its ongoing efforts to evaluate petroleum refineries’ compliance with BWON and NSPS QQQ. We cannot currently estimate the amount of any civil penalty or the timing of the resolution of these matters, but do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.
On August 30, 2012, MPC entered into a consent decree with the EPA regarding the operation of flares at six of our refineries. The consent decree was modified on September 15, 2016. On December 20, 2023, MPC formally submitted a request to the EPA to terminate the consent decree. The EPA may seek payment of stipulated penalties for violations of the consent decree as a condition of termination. Based on negotiations with the EPA in the third quarter of 2024, we believe resolution of the stipulated penalty demands may result in the payment of $1 million or more, but do not believe any stipulated penalties will have a material impact on our consolidated results of operations, financial position or cash flows.
On August 4, 2025, the Washington Department of Ecology (“Washington DOE”) commenced an enforcement action against Tesoro Refining & Marketing Company LLC, a subsidiary of the Company, for allegedly violating provisions of the Washington Hazardous Waste Management Act and associated regulations. We are finalizing resolution of this matter with the Washington DOE and do not believe the final resolution will have a material impact on our consolidated results of operations, financial position or cash flows.
On August 29, 2025, MPLX acquired Northwind Delaware Holdings LLC (“Northwind Midstream”), including its subsidiary Northwind Midstream Partners LLC, which owns and operates a sour gas treating facility in Lea County, New Mexico. We have disclosed to the New Mexico Environment Department (“NMED”) excess air emissions from the facility flares. We initiated discussions with NMED to resolve this matter and have entered into a new owner audit agreement with NMED as result of those discussions. We do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.
Item 4. Mine Safety Disclosures
Not applicable
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the NYSE and traded under the symbol “MPC.” As of February 20, 2026, there were approximately 22,111 registered holders of our common stock.
Issuer Purchases of Equity Securities
The following table sets forth a summary of our purchases during the quarter ended December 31, 2025, of equity securities that are registered by MPC pursuant to Section 12 of the Securities Exchange Act of 1934, as amended:
| Millions of Dollars | ||||||||||||||||||||||||||
| Period | Total Number of Shares Purchased | Average Price Paid per Share(a) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)(c) | ||||||||||||||||||||||
| 10/1/2025-10/31/2025 | 539,086 | $ | 185.75 | 539,086 | $ | 5,281 | ||||||||||||||||||||
| 11/1/2025-11/30/2025 | 2,078,982 | 194.34 | 2,078,982 | 4,877 | ||||||||||||||||||||||
| 12/1/2025-12/31/2025 | 2,622,197 | 189.14 | 2,622,197 | 4,381 | ||||||||||||||||||||||
| Total | 5,240,265 | 190.86 | 5,240,265 | |||||||||||||||||||||||
(a) Amounts in this column reflect the weighted average price paid for shares repurchased under our share repurchase authorizations. The weighted average price includes any commissions paid to brokers during the relevant period. The weighted average price does not include any excise tax incurred on the share repurchases.
(b) On April 30, 2024, we announced that our board of directors had approved a $5.0 billion share repurchase authorization. On November 5, 2024, we announced that our board of directors had approved an additional $5.0 billion share repurchases authorization. These share repurchase authorizations have no expiration date.
(c) The maximum dollar value remaining has been reduced by the amount of any commissions paid to brokers. The maximum dollar value remaining has not been reduced by the amount of any excise tax incurred on the share repurchases.
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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 strong results and continued growth in 2025, benefitting 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 opportunities to support the development plans of its producer customers.
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, improving efficiency, 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) | 2025 | 2024 | |||||||||
| Segment adjusted EBITDA for reportable segments | |||||||||||
| Refining & Marketing | $ | 6,138 | $ | 5,703 | |||||||
| Midstream | 6,750 | 6,544 | |||||||||
| Renewable Diesel | (110) | (150) | |||||||||
| Total reportable segments | $ | 12,778 | $ | 12,097 | |||||||
| Reconciliation of segment adjusted EBITDA for reportable segments to income before income taxes | |||||||||||
| Total reportable segments | $ | 12,778 | $ | 12,097 | |||||||
| Corporate | (822) | (774) | |||||||||
| Refining & Renewable Diesel planned turnaround costs | (1,553) | (1,404) | |||||||||
Renewable Diesel JV planned turnaround costs(a) | (18) | (9) | |||||||||
| LIFO inventory adjustment | 72 | 161 | |||||||||
Gain on sale of assets(b) | 897 | 151 | |||||||||
| SRE | 57 | — | |||||||||
Transaction-related costs(c) | (33) | — | |||||||||
| Legal settlements | 253 | — | |||||||||
| Depreciation and amortization | (3,251) | (3,337) | |||||||||
Renewable Diesel JV depreciation and amortization(a) | (89) | (89) | |||||||||
| Net interest and other financial costs | (1,276) | (839) | |||||||||
| Income before income taxes | $ | 7,015 | $ | 5,957 | |||||||
| Net Income attributable to MPC per diluted share | $ | 13.22 | $ | 10.08 | |||||||
(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.
| (Millions of dollars) | ||||||||
Blended crack spread sensitivity(a) (per $1.00/barrel change) | $ | 1,125 | ||||||
Sour differential sensitivity(b) (per $1.00/barrel change) | 520 | |||||||
Sweet differential sensitivity(c) (per $1.00/barrel change) | 520 | |||||||
Natural gas price sensitivity(d) (per $1.00/MMBtu) | 360 | |||||||
(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 | 2024 | 2025 vs. 2024 Variance | 2023 | 2024 vs. 2023 Variance | |||||||||||||||||||||||||||
| Revenues and other income: | ||||||||||||||||||||||||||||||||
| Sales and other operating revenues | $ | 132,699 | $ | 138,864 | $ | (6,165) | $ | 148,379 | $ | (9,515) | ||||||||||||||||||||||
| Income from equity method investments | 1,622 | 1,048 | 574 | 742 | 306 | |||||||||||||||||||||||||||
| Net gain on disposal of assets | 173 | 28 | 145 | 217 | (189) | |||||||||||||||||||||||||||
| Other income | 728 | 472 | 256 | 969 | (497) | |||||||||||||||||||||||||||
| Total revenues and other income | 135,222 | 140,412 | (5,190) | 150,307 | (9,895) | |||||||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||||||||
| Cost of revenues (excludes items below) | 119,446 | 126,240 | (6,794) | 128,566 | (2,326) | |||||||||||||||||||||||||||
| Depreciation and amortization | 3,251 | 3,337 | (86) | 3,307 | 30 | |||||||||||||||||||||||||||
| Selling, general and administrative expenses | 3,349 | 3,221 | 128 | 3,039 | 182 | |||||||||||||||||||||||||||
| Other taxes | 885 | 818 | 67 | 881 | (63) | |||||||||||||||||||||||||||
| Total costs and expenses | 126,931 | 133,616 | (6,685) | 135,793 | (2,177) | |||||||||||||||||||||||||||
| Income from continuing operations | 8,291 | 6,796 | 1,495 | 14,514 | (7,718) | |||||||||||||||||||||||||||
| Net interest and other financial costs | 1,276 | 839 | 437 | 525 | 314 | |||||||||||||||||||||||||||
| Income before income taxes | 7,015 | 5,957 | 1,058 | 13,989 | (8,032) | |||||||||||||||||||||||||||
| Provision for income taxes | 1,137 | 890 | 247 | 2,817 | (1,927) | |||||||||||||||||||||||||||
| Net income | 5,878 | 5,067 | 811 | 11,172 | (6,105) | |||||||||||||||||||||||||||
| Less net income attributable to: | ||||||||||||||||||||||||||||||||
| Redeemable noncontrolling interest | — | 27 | (27) | 94 | (67) | |||||||||||||||||||||||||||
| Noncontrolling interests | 1,831 | 1,595 | 236 | 1,397 | 198 | |||||||||||||||||||||||||||
| Net income attributable to MPC | $ | 4,047 | $ | 3,445 | $ | 602 | $ | 9,681 | $ | (6,236) | ||||||||||||||||||||||
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 | 2025 | 2024 | 2023 | |||||||||||||||||
Net refinery throughput (mbpd) | 2,989 | 2,922 | 2,903 | |||||||||||||||||
Refining & Marketing margin per barrel(a)(b) | $ | 16.87 | $ | 16.01 | $ | 23.00 | ||||||||||||||
| Less: | ||||||||||||||||||||
Refining operating costs per barrel(c) | 5.59 | 5.34 | 5.31 | |||||||||||||||||
Distribution costs per barrel(d) | 5.67 | 5.48 | 5.33 | |||||||||||||||||
| LIFO inventory adjustment | 0.07 | 0.10 | (0.15) | |||||||||||||||||
Other per barrel(e) | (0.09) | (0.24) | (0.43) | |||||||||||||||||
| Refining & Marketing adjusted EBITDA per barrel | $ | 5.63 | $ | 5.33 | $ | 12.94 | ||||||||||||||
| Refining planned turnaround costs per barrel | $ | 1.39 | $ | 1.31 | $ | 1.11 | ||||||||||||||
| Depreciation and amortization per barrel | 1.49 | 1.65 | 1.72 | |||||||||||||||||
| Per barrel fees paid to MPLX included in distribution costs above | 3.69 | 3.70 | 3.62 | |||||||||||||||||
(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) | 2025 | 2024 | 2023 | |||||||||||||||||
| Chicago CBOB unleaded regular gasoline | $ | 1.92 | $ | 2.14 | $ | 2.33 | ||||||||||||||
| Chicago ultra-low sulfur diesel | 2.17 | 2.32 | 2.61 | |||||||||||||||||
| USGC CBOB unleaded regular gasoline | 1.91 | 2.13 | 2.34 | |||||||||||||||||
| USGC ultra-low sulfur diesel | 2.22 | 2.36 | 2.72 | |||||||||||||||||
| LA CARBOB | 2.31 | 2.46 | 2.81 | |||||||||||||||||
| LA CARB diesel | 2.36 | 2.44 | 2.91 | |||||||||||||||||
Market Indicators (dollars per barrel) | ||||||||||||||||||||
| WTI | $ | 64.73 | $ | 75.76 | $ | 77.60 | ||||||||||||||
| MEH | 65.87 | 77.35 | 79.08 | |||||||||||||||||
| ANS | 69.72 | 80.31 | 82.41 | |||||||||||||||||
| Crack Spreads | ||||||||||||||||||||
| Mid-Continent WTI 3-2-1 | $ | 13.92 | $ | 14.09 | $ | 18.61 | ||||||||||||||
| USGC MEH 3-2-1 | 12.70 | 11.75 | 17.49 | |||||||||||||||||
| West Coast ANS 3-2-1 | 22.13 | 19.03 | 30.11 | |||||||||||||||||
Blended 3-2-1(a) | 14.89 | 14.03 | 20.46 | |||||||||||||||||
| Crude Oil Differentials | ||||||||||||||||||||
| Sweet | $ | (0.73) | $ | (1.09) | $ | (0.48) | ||||||||||||||
| Sour | (2.76) | (4.45) | (6.31) | |||||||||||||||||
(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
| 2025 | 2024 | 2023 | ||||||||||||||||||
| Refining & Marketing Operating Statistics | ||||||||||||||||||||
Crude oil capacity utilization percent(a) | 94 | 92 | 92 | |||||||||||||||||
Refinery throughputs (mbpd): | ||||||||||||||||||||
| Crude oil refined | 2,787 | 2,714 | 2,677 | |||||||||||||||||
| Other charge and blendstocks | 202 | 208 | 226 | |||||||||||||||||
| Net refinery throughput | 2,989 | 2,922 | 2,903 | |||||||||||||||||
| Sour crude oil throughput percent | 45 | 44 | 44 | |||||||||||||||||
| Sweet crude oil throughput percent | 55 | 56 | 56 | |||||||||||||||||
Refined product yields (mbpd): | ||||||||||||||||||||
| Gasoline | 1,499 | 1,490 | 1,526 | |||||||||||||||||
| Distillates | 1,093 | 1,070 | 1,037 | |||||||||||||||||
| Propane | 67 | 67 | 66 | |||||||||||||||||
| NGLs and petrochemicals | 195 | 192 | 182 | |||||||||||||||||
| Heavy fuel oil | 90 | 59 | 52 | |||||||||||||||||
| Asphalt | 79 | 81 | 80 | |||||||||||||||||
| Total | 3,023 | 2,959 | 2,943 | |||||||||||||||||
Refined product export sales volumes (mbpd)(b) | 401 | 402 | 363 | |||||||||||||||||
(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 | 2025 | 2024 | 2023 | |||||||||||||||||
Natural Gas NYMEX HH (per MMBtu) | $ | 3.63 | $ | 2.41 | $ | 2.66 | ||||||||||||||
C2 + NGL Pricing (per gallon)(a) | $ | 0.79 | $ | 0.84 | $ | 0.69 | ||||||||||||||
(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) | 2025 | 2024 | 2023 | |||||||||||||||||
Corporate(a) | $ | (927) | $ | (864) | $ | (837) | ||||||||||||||
(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) | 2025 | 2024 | 2023 | |||||||||||||||||
| Items not allocated to segments: | ||||||||||||||||||||
| Gain on sale of assets | $ | 897 | $ | 151 | $ | 198 | ||||||||||||||
| SRE | 57 | — | — | |||||||||||||||||
| Transaction-related costs | (33) | — | — | |||||||||||||||||
| Legal settlements | 253 | — | — | |||||||||||||||||
| Total items not allocated to segments | $ | 1,174 | $ | 151 | $ | 198 | ||||||||||||||
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) | 2025 | 2024 | 2023 | ||||||||||||||||||||
| Refining & Marketing segment adjusted EBITDA | $ | 6,138 | $ | 5,703 | $ | 13,705 | |||||||||||||||||
| Plus (Less): | |||||||||||||||||||||||
| Depreciation and amortization | (1,627) | (1,767) | (1,822) | ||||||||||||||||||||
| Refining planned turnaround costs | (1,514) | (1,397) | (1,181) | ||||||||||||||||||||
| LIFO inventory adjustment | 82 | 106 | (157) | ||||||||||||||||||||
| Selling, general and administrative expenses | 2,632 | 2,472 | 2,443 | ||||||||||||||||||||
| Income from equity method investments | (9) | (57) | (66) | ||||||||||||||||||||
| Net (gain) loss on disposal of assets | 2 | (1) | (2) | ||||||||||||||||||||
| Other income | (347) | (342) | (870) | ||||||||||||||||||||
| Refining & Marketing gross margin | 5,357 | 4,717 | 12,050 | ||||||||||||||||||||
| Plus (Less): | |||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization) | 11,970 | 11,321 | 10,833 | ||||||||||||||||||||
| Depreciation and amortization | 1,627 | 1,767 | 1,822 | ||||||||||||||||||||
Gross margin excluded from and other income included in Refining & Marketing margin(a) | (289) | (425) | (45) | ||||||||||||||||||||
| Other taxes included in Refining & Marketing margin | (261) | (259) | (288) | ||||||||||||||||||||
| Refining & Marketing margin | $ | 18,404 | $ | 17,121 | $ | 24,372 | |||||||||||||||||
(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) | 2025 | 2024 | 2023 | ||||||||||||||||||||
| Renewable Diesel segment adjusted EBITDA | $ | (110) | $ | (150) | $ | (64) | |||||||||||||||||
| Plus (Less): | |||||||||||||||||||||||
| Depreciation and amortization | (69) | (75) | (65) | ||||||||||||||||||||
Renewable Diesel JV depreciation and amortization(a) | (89) | (89) | (65) | ||||||||||||||||||||
| Renewable Diesel planned turnaround costs | (39) | (7) | (20) | ||||||||||||||||||||
Renewable Diesel JV planned turnaround costs(a) | (18) | (9) | (25) | ||||||||||||||||||||
| LIFO inventory adjustment | (10) | 55 | 12 | ||||||||||||||||||||
| Selling, general and administrative expenses | 35 | 59 | 61 | ||||||||||||||||||||
| (Income) loss from equity method investments | (82) | (70) | 59 | ||||||||||||||||||||
| Net gain on disposal of assets | — | — | (1) | ||||||||||||||||||||
| Other income | (33) | — | (1) | ||||||||||||||||||||
| Renewable Diesel gross margin | (415) | (286) | (109) | ||||||||||||||||||||
| Plus (Less): | |||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization) | 412 | 312 | 284 | ||||||||||||||||||||
| Depreciation and amortization | 69 | 75 | 65 | ||||||||||||||||||||
| Martinez JV depreciation and amortization | 85 | 85 | 64 | ||||||||||||||||||||
| Renewable Diesel margin | $ | 151 | $ | 186 | $ | 304 | |||||||||||||||||
(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) | 2025 | 2024 | 2023 | |||||||||||||||||
| Net cash provided by (used in): | ||||||||||||||||||||
| Operating activities | $ | 8,253 | $ | 8,665 | $ | 14,117 | ||||||||||||||
| Investing activities | (5,867) | 1,534 | (3,095) | |||||||||||||||||
| Financing activities | (1,924) | (12,434) | (14,207) | |||||||||||||||||
| Total increase (decrease) in cash | $ | 462 | $ | (2,235) | $ | (3,185) | ||||||||||||||
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) | 2025 | 2024 | 2023 | |||||||||||||||||
| Additions to property, plant and equipment per consolidated statements of cash flows | $ | 3,486 | $ | 2,533 | $ | 1,890 | ||||||||||||||
| Increase in capital accruals | 143 | 34 | 184 | |||||||||||||||||
| Total capital expenditures | 3,629 | 2,567 | 2,074 | |||||||||||||||||
| Investments in equity method investees | 1,064 | 509 | 480 | |||||||||||||||||
| Total capital expenditures and investments | $ | 4,693 | $ | 3,076 | $ | 2,554 | ||||||||||||||
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 | $ | 5,000 | $ | — | $ | 1 | $ | 4,999 | ||||||||||||||||||
Trade receivables facility(a) | 100 | — | — | 100 | ||||||||||||||||||||||
| Total | $ | 5,100 | $ | — | $ | 1 | $ | 5,099 | ||||||||||||||||||
Cash and cash equivalents and short-term investments(b) | 1,535 | |||||||||||||||||||||||||
| Total liquidity | $ | 6,634 | ||||||||||||||||||||||||
(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 | $ | 2,000 | $ | — | $ | — | $ | 2,000 | ||||||||||||||||||
| MPC intercompany loan agreement | 1,500 | — | — | 1,500 | ||||||||||||||||||||||
| Total | $ | 3,500 | $ | — | $ | — | $ | 3,500 | ||||||||||||||||||
| Cash and cash equivalents | 2,137 | |||||||||||||||||||||||||
| Total liquidity | $ | 5,637 | ||||||||||||||||||||||||
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 | 2025 | 2024 | 2023 | ||||||||||||||||||||||
Capital expenditures and investments:(a) | ||||||||||||||||||||||||||
| MPC, excluding MPLX | ||||||||||||||||||||||||||
| Refining & Marketing | $ | 1,410 | $ | 1,580 | $ | 1,445 | $ | 998 | ||||||||||||||||||
| Midstream - Other | 40 | 25 | 7 | 2 | ||||||||||||||||||||||
| Renewable Diesel | — | 19 | 8 | 313 | ||||||||||||||||||||||
Corporate and Other(b) | 50 | 25 | 63 | 83 | ||||||||||||||||||||||
| Total MPC, excluding MPLX | $ | 1,500 | $ | 1,649 | $ | 1,523 | $ | 1,396 | ||||||||||||||||||
Midstream - MPLX(c)(d) | $ | 2,700 | $ | 2,950 | $ | 1,497 | $ | 1,103 | ||||||||||||||||||
(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 maintenance 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) | 2025 | 2024 | 2023 | ||||||||||||||
| Number of shares repurchased | 21 | 53 | 89 | ||||||||||||||
Cash paid for shares repurchased(a) | $ | 3,399 | $ | 9,077 | $ | 11,572 | |||||||||||
Average cost per share(b) | $ | 163.64 | $ | 171.68 | $ | 131.27 | |||||||||||
(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) | 2025 | 2024 | 2023 | ||||||||||||||
| Number of common units repurchased | 8 | 8 | — | ||||||||||||||
| Cash paid for common units repurchased | $ | 400 | $ | 326 | $ | — | |||||||||||
| Average cost per unit | $ | 51.58 | $ | 43.04 | $ | — | |||||||||||
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) | 2025 | 2024 | 2023 | |||||||||||||||||
| Capital | $ | 706 | $ | 543 | $ | 236 | ||||||||||||||
Compliance:(a) | ||||||||||||||||||||
| Operating and maintenance | 1,381 | 1,390 | 1,191 | |||||||||||||||||
Remediation(b) | 49 | 56 | 49 | |||||||||||||||||
| Total | $ | 2,136 | $ | 1,989 | $ | 1,476 | ||||||||||||||
(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 impairment loss 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.
Item 8. Financial Statements and Supplementary Data – Note 24 includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive loss reported on the year-end balance sheets.
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ACCOUNTING STANDARDS NOT YET ADOPTED
Refer to Item 8. Financial Statements and Supplementary Data – Note 3 to our audited consolidated financial statements for recently issued financial accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
GENERAL
We are exposed to market risks related to the volatility of crude oil and refined petroleum products, ethanol, renewable feedstock, renewable products, NGLs, and natural gas prices. We employ various strategies, including the use of commodity derivative instruments, to hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. As of December 31, 2025, we did not have any financial derivative instruments to hedge the risks related to interest rate or foreign currency exchange rate fluctuations; however, we have used them in the past, and we continually monitor the market and our exposure and may enter into these agreements again in the future. We are at risk for changes in fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.
We believe that our use of derivative instruments, along with our risk assessment procedures and internal controls, does not expose us to material adverse consequences. While the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.
See Item 8. Financial Statements and Supplementary Data – Notes 17 and 18 for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.
Commodity Price Risk
Refining & Marketing
Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures, swaps and options, as part of an overall program to hedge commodity price risk. We also do a limited amount of trading not directly related to our physical transactions.
We use derivative instruments related to the acquisition of crude oil and ethanol blended with refined petroleum products to hedge price risk associated with market volatility between the time we purchase the product and when we use it in the refinery production process or it is blended. In addition, we may use commodity derivative instruments on fixed price contracts for the sale of refined products to hedge risk by converting the refined product sales to market-based prices. The majority of these derivatives are exchange-traded contracts, but we may also enter into over-the-counter swaps, options and over-the-counter options. We closely monitor and hedge our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Our positions are monitored daily by a risk control group to ensure compliance with our stated risk management policy.
Midstream
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 MPLX’s control. MPLX may at times use a variety of commodity derivative instruments, including futures and options, as part of an overall program to economically hedge commodity price risk. A portion of MPLX’s profitability is directly affected by prevailing commodity prices primarily as a result of purchasing and selling NGLs and natural gas at index-related prices. To the extent that commodity prices influence the level of drilling by MPLX producer customers, such prices also indirectly affect profitability. MPLX may enter into derivative contracts, which are primarily swaps traded on the OTC market as well as fixed price forward contracts. MPLX’s risk management policy does not allow it to enter into speculative positions with its derivative contracts. Execution of MPLX’s hedge strategy and the continuous monitoring of commodity markets and its open derivative positions are carried out by its hedge committee, comprised of members of senior management.
To mitigate MPLX’s cash flow exposure to fluctuations in the price of NGLs, it may use NGL derivative swap contracts. A small portion of its NGL price exposure may be managed by using crude oil contracts. To mitigate MPLX’s cash flow exposure to fluctuations in the price of natural gas, it may use natural gas derivative swap contracts, taking into account the partial offset of its long and short natural gas positions resulting from normal operating activities.
MPLX would be exposed to additional commodity risk in certain situations such as if producers under‑deliver or over‑deliver products or if processing facilities are operated in different recovery modes. In the event that MPLX has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.
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MPLX management conducts a standard credit review on counterparties to derivative contracts, and it has provided the counterparties with a guaranty as credit support for its obligations if requested. MPLX uses standardized agreements that allow for offset of certain positive and negative exposures in the event of default or other terminating events, including bankruptcy.
Renewable Diesel
MPC is exposed to commodity price risk related to the acquisition of renewable feedstocks and the sale of renewable diesel. To manage these risks, we employ hedging strategies in accordance with our objectives and company policies. We are subject to price volatility mainly in agricultural commodities markets in relation to renewable feedstock used in the production of renewable diesel. To mitigate this risk, we use futures contracts traded on commodity exchanges as hedging instruments. We are also exposed to market volatility between the time the renewable product is produced and when it is sold. We employ hedging strategies with exchange traded instruments in commodity markets to minimize the impact of price volatility during this time.
While these hedging activities are intended to reduce price volatility, they do not completely eliminate commodity price risk. We continually monitor commodity price exposures and adjust our hedging as necessary to align with market conditions, regulatory requirements, internal price risk management policies, and overall business objectives.
Open Derivative Positions and Sensitivity Analysis
The following table includes the composition of net losses/gains on our commodity derivative positions for the years ended December 31, 2025 and 2024, respectively.
| (Millions of dollars) | 2025 | 2024 | ||||||||||||
| Realized loss on settled derivative positions | $ | (52) | $ | (94) | ||||||||||
| Unrealized gain on open net derivative positions | 28 | 3 | ||||||||||||
| Net loss | $ | (24) | $ | (91) | ||||||||||
See Item 8. Financial Statements and Supplementary Data – Note 18 for additional information on our open derivative positions at December 31, 2025.
Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices for open commodity derivative instruments as of December 31, 2025 is provided in the following table.
| Change in IFO from a Hypothetical Price Increase of | Change in IFO from a Hypothetical Price Decrease of | |||||||||||||||||||||||||
| (Millions of dollars) | 10% | 25% | 10% | 25% | ||||||||||||||||||||||
| As of December 31, 2025 | ||||||||||||||||||||||||||
| Crude | $ | (10) | $ | (25) | $ | 10 | $ | 25 | ||||||||||||||||||
| Refined products | (13) | (33) | 13 | 33 | ||||||||||||||||||||||
| Blending products | (1) | (3) | 1 | 3 | ||||||||||||||||||||||
| Soybean oil | (4) | (10) | 4 | 10 | ||||||||||||||||||||||
We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the above sensitivity analysis.
We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. Changes to the portfolio after December 31, 2025 would cause future IFO effects to differ from those presented above.
Interest Rate Risk
Our use of fixed or variable-rate debt directly exposes us to interest rate risk. Fixed rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates or that our current fixed rate debt may be higher than the current market. Variable-rate debt, such as borrowings under our revolving credit facilities, exposes us to short-term changes in market rates that impact our interest expense. See Item 8. Financial Statements and Supplementary Data – Note 19 for additional information on our debt.
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt, including the portion classified as current and excluding finance leases, as of December 31, 2025 is provided in the following table. The fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and, in addition to
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short-term investments which are recorded at fair value, are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
| (Millions of dollars) | Fair Value(a) | Change in Fair Value(b) | Change in Net Income for the Year ended December 31, 2025(c) | |||||||||||||||||
| Long-term debt | ||||||||||||||||||||
| Fixed-rate | $ | 31,331 | $ | 2,494 | n/a | |||||||||||||||
| Variable-rate | $ | — | $ | — | $ | — | ||||||||||||||
(a) Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.
(b) Assumes a 100-basis point decrease in the weighted average yield-to-maturity at December 31, 2025.
(c) Assumes a 100-basis-point change in interest rates. The change in net income was based on the weighted average balance of debt outstanding for the year ended December 31, 2025.
See Item 8. Financial Statements and Supplementary Data – Note 17 for additional information on the fair value of our debt.
Foreign Currency Exchange Rate Risk
We are exposed to exchange rate fluctuations related to our foreign operations in Canada and Mexico. We did not use derivatives to hedge our market risk exposure to these foreign exchange rate fluctuations in 2025.
Counterparty Risk
MPLX is subject to risk of loss resulting from nonpayment by its customers to whom it provides services, leases assets, or sells natural gas or NGLs. MPLX believes that certain contracts where it sells NGLs and acts as its producer customers’ agent would allow it to pass those losses through to its customers, thus reducing its risk, when it is selling NGLs and acting as its producer customers’ agent. Its credit exposure related to these customers is represented by the value of its trade receivables or lease receivables. Where exposed to credit risk, MPLX analyzes the customer’s financial condition prior to entering into a transaction or agreement, establishes credit terms and monitors the appropriateness of these terms on an ongoing basis. In the event of a customer default, MPLX may sustain a loss and its cash receipts could be negatively impacted.
We are subject to risk of loss resulting from nonpayment or nonperformance by counterparties to our derivative contracts. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value at the reporting date. Outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
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Item 8. Financial Statements and Supplementary Data
INDEX
| Page | ||||||||
(PCAOB ID 238) | ||||||||
| Audited Consolidated Financial Statements: | ||||||||
Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPC,” “us,” “our,” “we” or the “Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries.
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Management’s Responsibilities for Financial Statements
The accompanying consolidated financial statements of Marathon Petroleum Corporation and its subsidiaries (“MPC”) are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States of America. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
MPC seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organizational arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The board of directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit Committee. This committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
| /s/ Maryann T. Mannen | /s/ Maria A. Khoury | /s/ Erin M. Brzezinski | ||||||||||||
| Maryann T. Mannen Chairman of the Board, President and Chief Executive Officer | Maria A. Khoury Executive Vice President and Chief Financial Officer | Erin M. Brzezinski Vice President and Controller | ||||||||||||
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Marathon Petroleum Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Marathon Petroleum Corporation and its subsidiaries (the "Company") as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income, of equity and redeemable noncontrolling interest and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Northwind Midstream from its assessment of internal control over financial reporting as of December 31, 2025, because it was acquired by the Company in a purchase business combination during 2025. We have also excluded Northwind Midstream from our audit of internal control over financial reporting. Northwind Midstream is a wholly-owned subsidiary whose total assets and total revenues and other income excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 2% and less than 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Acquisition of Northwind Midstream - Valuation of Intangibles
As described in Note 5 to the consolidated financial statements, on August 29, 2025, the Company completed the acquisition of 100 percent of Northwind Midstream for $2.4 billion in cash. Of the total assets acquired, $951 million relates to intangibles. The fair value of the identifiable intangible assets was primarily based on the multi-period excess earnings method, which is an income approach. As disclosed by management, a significant amount of judgment is involved in estimating the fair value of intangible assets. The income approach requires management to project future volumes and associated cash flows, and apply a discount rate.
The principal considerations for our determination that performing procedures relating to the valuation of intangibles acquired in the acquisition of Northwind Midstream is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the intangibles acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future volumes and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to acquisition accounting, including controls over management’s valuation of the intangibles acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the intangibles acquired; (iii) evaluating the appropriateness of the multi-period excess earnings method used by management; (iv) testing the completeness and accuracy of the underlying data used in the multi-period excess earnings method; and (v) evaluating the reasonableness of the significant assumptions used by management related to future volumes and the discount rate. Evaluating management’s assumption related to future volumes involved considering (i) the consistency with external market and industry data and (ii) whether the assumption was consistent with executed customer contracts. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the multi-period excess earnings method and (ii) the reasonableness of the discount rate assumption.
/s/ PricewaterhouseCoopers LLP
Toledo, Ohio
February 26, 2026
We have served as the Company’s auditor since 2010.
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Marathon Petroleum Corporation
Consolidated Statements of Income
| (In millions, except per share data) | 2025 | 2024 | 2023 | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Sales and other operating revenues | $ | 132,699 | $ | 138,864 | $ | 148,379 | |||||||||||
| Income from equity method investments | 1,622 | 1,048 | 742 | ||||||||||||||
| Net gain on disposal of assets | 173 | 28 | 217 | ||||||||||||||
| Other income | 728 | 472 | 969 | ||||||||||||||
| Total revenues and other income | 135,222 | 140,412 | 150,307 | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Cost of revenues (excludes items below) | 119,446 | 126,240 | 128,566 | ||||||||||||||
| Depreciation and amortization | 3,251 | 3,337 | 3,307 | ||||||||||||||
| Selling, general and administrative expenses | 3,349 | 3,221 | 3,039 | ||||||||||||||
| Other taxes | 885 | 818 | 881 | ||||||||||||||
| Total costs and expenses | 126,931 | 133,616 | 135,793 | ||||||||||||||
| Income from operations | 8,291 | 6,796 | 14,514 | ||||||||||||||
| Net interest and other financial costs | 1,276 | 839 | 525 | ||||||||||||||
| Income before income taxes | 7,015 | 5,957 | 13,989 | ||||||||||||||
| Provision for income taxes | 1,137 | 890 | 2,817 | ||||||||||||||
| Net income | 5,878 | 5,067 | 11,172 | ||||||||||||||
| Less net income attributable to: | |||||||||||||||||
| Redeemable noncontrolling interest | — | 27 | 94 | ||||||||||||||
| Noncontrolling interests | 1,831 | 1,595 | 1,397 | ||||||||||||||
| Net income attributable to MPC | $ | 4,047 | $ | 3,445 | $ | 9,681 | |||||||||||
Per share data (See Note 8) | |||||||||||||||||
| Basic: | |||||||||||||||||
| Net income attributable to MPC per share | $ | 13.24 | $ | 10.11 | $ | 23.73 | |||||||||||
| Weighted average shares outstanding | 305 | 340 | 407 | ||||||||||||||
| Diluted: | |||||||||||||||||
| Net income attributable to MPC per share | $ | 13.22 | $ | 10.08 | $ | 23.63 | |||||||||||
| Weighted average shares outstanding | 306 | 341 | 409 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
77
Marathon Petroleum Corporation
Consolidated Statements of Comprehensive Income
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Net income | $ | 5,878 | $ | 5,067 | $ | 11,172 | |||||||||||
| Defined benefit plans: | |||||||||||||||||
Actuarial changes, net of tax of $10, $20 and $(24), respectively | 32 | 60 | (85) | ||||||||||||||
Prior service, net of tax of $(8), $(14) and $(18), respectively | (23) | (41) | (49) | ||||||||||||||
Other, net of tax of $—, $1 and $—, respectively | — | (2) | 1 | ||||||||||||||
| Other comprehensive income (loss) | 9 | 17 | (133) | ||||||||||||||
| Comprehensive income | 5,887 | 5,084 | 11,039 | ||||||||||||||
| Less comprehensive income attributable to: | |||||||||||||||||
| Redeemable noncontrolling interest | — | 27 | 94 | ||||||||||||||
| Noncontrolling interests | 1,831 | 1,595 | 1,397 | ||||||||||||||
| Comprehensive income attributable to MPC | $ | 4,056 | $ | 3,462 | $ | 9,548 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
78
Marathon Petroleum Corporation
Consolidated Balance Sheets
| December 31, | |||||||||||
| (Millions of dollars, except share data) | 2025 | 2024 | |||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | 3,672 | $ | 3,210 | |||||||
Receivables, less allowance for expected credit loss of $20 and $73, respectively | 10,317 | 11,145 | |||||||||
| Inventories | 10,129 | 9,568 | |||||||||
| Other current assets | 662 | 524 | |||||||||
| Total current assets | 24,780 | 24,447 | |||||||||
| Equity method investments | 6,795 | 6,857 | |||||||||
| Property, plant and equipment, net | 37,397 | 35,028 | |||||||||
| Goodwill | 9,354 | 8,244 | |||||||||
| Intangibles, net | 2,714 | 1,774 | |||||||||
| Right of use assets, net | 1,493 | 1,300 | |||||||||
| Other noncurrent assets | 1,422 | 1,208 | |||||||||
| Total assets | $ | 83,955 | $ | 78,858 | |||||||
| Liabilities | |||||||||||
| Accounts payable | $ | 12,974 | $ | 13,906 | |||||||
| Payroll and benefits payable | 1,107 | 1,096 | |||||||||
| Accrued taxes | 1,484 | 1,204 | |||||||||
| Debt due within one year | 2,371 | 3,049 | |||||||||
| Operating lease liabilities | 489 | 417 | |||||||||
| Other current liabilities | 1,253 | 1,155 | |||||||||
| Total current liabilities | 19,678 | 20,827 | |||||||||
| Long-term debt | 30,505 | 24,432 | |||||||||
| Deferred income taxes | 5,984 | 5,771 | |||||||||
| Defined benefit postretirement plan obligations | 1,173 | 1,157 | |||||||||
| Long-term operating lease liabilities | 993 | 860 | |||||||||
| Deferred credits and other liabilities | 1,536 | 1,305 | |||||||||
| Total liabilities | 59,869 | 54,352 | |||||||||
Commitments and contingencies (see Note 27) | |||||||||||
| Redeemable noncontrolling interest | — | 203 | |||||||||
| Equity | |||||||||||
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized) | — | — | |||||||||
| Common stock: | |||||||||||
Issued – 994 million and 994 million shares (par value $0.01 per share, 2 billion shares authorized) | 10 | 10 | |||||||||
Held in treasury, at cost – 699 million and 678 million shares | (56,027) | (52,623) | |||||||||
| Additional paid-in capital | 33,685 | 33,624 | |||||||||
| Retained earnings | 39,751 | 36,848 | |||||||||
| Accumulated other comprehensive loss | (105) | (114) | |||||||||
| Total MPC stockholders’ equity | 17,314 | 17,745 | |||||||||
| Noncontrolling interests | 6,772 | 6,558 | |||||||||
| Total equity | 24,086 | 24,303 | |||||||||
| Total liabilities, redeemable noncontrolling interest and equity | $ | 83,955 | $ | 78,858 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
79
Marathon Petroleum Corporation
Consolidated Statements of Cash Flows
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Operating activities: | |||||||||||||||||
| Net income | $ | 5,878 | $ | 5,067 | $ | 11,172 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||
| Amortization of deferred financing costs and debt discount | 39 | (31) | (78) | ||||||||||||||
| Depreciation and amortization | 3,251 | 3,337 | 3,307 | ||||||||||||||
| Pension and other postretirement benefits, net | 16 | 59 | (191) | ||||||||||||||
| Deferred income taxes | 282 | (124) | (28) | ||||||||||||||
| Net gain on disposal of assets | (173) | (28) | (217) | ||||||||||||||
| Income from equity method investments | (1,622) | (1,048) | (742) | ||||||||||||||
| Distributions from equity method investments | 1,255 | 1,215 | 941 | ||||||||||||||
| Changes in the fair value of derivative instruments | (16) | 71 | 70 | ||||||||||||||
| Changes in: | |||||||||||||||||
| Current receivables | 890 | 1,117 | 2,109 | ||||||||||||||
| Inventories | (596) | (270) | (489) | ||||||||||||||
| Current liabilities and other current assets | (776) | (438) | (1,318) | ||||||||||||||
| Right of use assets and operating lease liabilities, net | 13 | (10) | (7) | ||||||||||||||
| All other, net | (188) | (252) | (412) | ||||||||||||||
| Net cash provided by operating activities | 8,253 | 8,665 | 14,117 | ||||||||||||||
| Investing activities: | |||||||||||||||||
| Additions to property, plant and equipment | (3,486) | (2,533) | (1,890) | ||||||||||||||
| Acquisitions, net of cash acquired | (3,316) | (688) | (246) | ||||||||||||||
| Disposal of assets | 1,005 | 35 | 36 | ||||||||||||||
| Investments – acquisitions and contributions | (1,064) | (509) | (480) | ||||||||||||||
| Investments – redemptions, repayments, return of capital and sales proceeds | 721 | 161 | 275 | ||||||||||||||
| Purchases of short-term investments | — | (2,949) | (8,622) | ||||||||||||||
| Sales of short-term investments | — | 3,295 | 2,082 | ||||||||||||||
| Maturities of short-term investments | — | 4,526 | 5,048 | ||||||||||||||
| All other, net | 273 | 196 | 702 | ||||||||||||||
| Net cash provided by (used in) investing activities | (5,867) | 1,534 | (3,095) | ||||||||||||||
| Financing activities: | |||||||||||||||||
| Commercial paper – issued | 5,055 | — | — | ||||||||||||||
| Commercial paper– repayments | (5,055) | — | — | ||||||||||||||
| Long-term debt – borrowings | 11,166 | 1,631 | 1,589 | ||||||||||||||
| Long-term debt – repayments | (6,463) | (1,984) | (1,079) | ||||||||||||||
| Debt issuance costs | (80) | (15) | (15) | ||||||||||||||
| Issuance of common stock | 24 | 25 | 62 | ||||||||||||||
| Common stock repurchased | (3,488) | (9,189) | (11,572) | ||||||||||||||
| Dividends paid | (1,140) | (1,154) | (1,261) | ||||||||||||||
| Distributions to noncontrolling interests | (1,513) | (1,377) | (1,281) | ||||||||||||||
| Repurchases of noncontrolling interests | (400) | (326) | — | ||||||||||||||
| Redemption of noncontrolling interests - preferred units | — | — | (600) | ||||||||||||||
| All other, net | (30) | (45) | (50) | ||||||||||||||
| Net cash used in financing activities | (1,924) | (12,434) | (14,207) | ||||||||||||||
| Net change in cash, cash equivalents and restricted cash | $ | 462 | $ | (2,235) | $ | (3,185) | |||||||||||
Cash, cash equivalents and restricted cash at beginning of period(a) | 3,211 | 5,446 | 8,631 | ||||||||||||||
Cash, cash equivalents and restricted cash at end of period(a) | $ | 3,673 | $ | 3,211 | $ | 5,446 | |||||||||||
(a) Restricted cash is included in other current assets on our consolidated balance sheets.
The accompanying notes are an integral part of these consolidated financial statements.
80
Marathon Petroleum Corporation
Consolidated Statements of Equity and Redeemable Noncontrolling Interest
| MPC Stockholders’ Equity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Non-controlling Interests | Total Equity | Redeemable Non-controlling Interest | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Shares in millions; amounts in millions of dollars) | Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2022 | 990 | $ | 10 | (536) | $ | (31,841) | $ | 33,402 | $ | 26,142 | $ | 2 | $ | 6,404 | $ | 34,119 | $ | 968 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 9,681 | — | 1,397 | 11,078 | 94 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends declared on common stock ($3.075 per share) | — | — | — | — | — | (1,261) | — | — | (1,261) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (1,187) | (1,187) | (94) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | — | — | (133) | — | (133) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares repurchased | — | — | (89) | (11,661) | — | — | — | — | (11,661) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-based compensation | 3 | — | — | — | 67 | 2 | — | 6 | 75 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity transactions of MPLX | — | — | — | — | (4) | (2) | — | (520) | (526) | (73) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2023 | 993 | $ | 10 | (625) | $ | (43,502) | $ | 33,465 | $ | 34,562 | $ | (131) | $ | 6,100 | $ | 30,504 | $ | 895 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 3,445 | — | 1,595 | 5,040 | 27 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends declared on common stock ($3.385 per share) | — | — | — | — | — | (1,154) | — | — | (1,154) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (1,333) | (1,333) | (44) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | 17 | — | 17 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares repurchased | — | — | (53) | (9,121) | — | — | — | — | (9,121) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-based compensation | 1 | — | — | — | 55 | (5) | — | 7 | 57 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity transactions of MPLX | — | — | — | — | 104 | — | — | 189 | 293 | (675) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2024 | 994 | $ | 10 | (678) | $ | (52,623) | $ | 33,624 | $ | 36,848 | $ | (114) | $ | 6,558 | $ | 24,303 | $ | 203 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 4,047 | — | 1,831 | 5,878 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends declared on common stock ($3.73 per share) | — | — | — | — | — | (1,140) | — | — | (1,140) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (1,507) | (1,507) | (6) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | 9 | — | 9 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares repurchased | — | — | (21) | (3,404) | — | — | — | — | (3,404) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-based compensation | — | — | — | — | 75 | (4) | — | 4 | 75 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity transactions of MPLX | — | — | — | — | (14) | — | — | (114) | (128) | (197) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2025 | 994 | $ | 10 | (699) | $ | (56,027) | $ | 33,685 | $ | 39,751 | $ | (105) | $ | 6,772 | $ | 24,086 | $ | — | ||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
81
Notes to Consolidated Financial Statements
1. Description of the Business and Basis of Presentation
Description of the Business
We are a leading, integrated, downstream and midstream energy company headquartered in Findlay, Ohio. We operate one of the nation's largest refining systems. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market and to independent entrepreneurs who operate branded outlets. We also sell transportation fuel to consumers through direct dealer locations under long-term supply contracts. MPC’s midstream operations are primarily conducted through MPLX, which owns and operates crude oil and light product transportation and logistics infrastructure as well as gathering, processing and fractionation assets. We own the general partner and a majority limited partner interest in MPLX. In addition, we produce and market renewable diesel in the United States.
Refer to Notes 4 and 10 for additional information about our operations.
Basis of Presentation
All significant intercompany transactions and accounts have been eliminated.
Certain prior period financial statement amounts have been reclassified to conform to current period presentation.
2. Summary of Principal Accounting Policies
Principles Applied in Consolidation
These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and MPLX. As of December 31, 2025, we owned the general partner of MPLX and approximately 64 percent of the outstanding MPLX common units. Due to our ownership of the general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and record a noncontrolling interest for the interest owned by the public. Changes in ownership interest in consolidated subsidiaries that do not result in a change in control are recorded as equity transactions.
Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.
Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for any excess related to goodwill. Equity method investments are evaluated for impairment whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value.
Use of Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires management 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. Actual results could differ from those estimates.
Revenue Recognition
We recognize revenue based on consideration specified in contracts or agreements with customers when we satisfy our performance obligations by transferring control over products or services to a customer. We made an accounting policy election that all taxes assessed by a governmental authority that are both imposed on and concurrent with a revenue-producing transaction and collected from our customers will be recognized on a net basis within sales and other operating revenues.
Our revenue recognition patterns are described below by reportable segment:
•Refining & Marketing and Renewable Diesel - The vast majority of our Refining & Marketing and Renewable Diesel contracts contain pricing that is based on the market price for the product at the time of delivery. Our obligations to deliver product volumes are typically satisfied and revenue is recognized when control of the product transfers to our customers. Concurrent with the transfer of control, we typically receive the right to payment for the delivered product, the customer accepts the product and the customer has significant risks and rewards of ownership of the product. Payment terms require customers to pay shortly after delivery and do not contain significant financing components.
•Midstream - Midstream revenue transactions typically are defined by contracts under which we sell a product or provide a service. Revenues from sales of product are recognized when control of the product transfers to the customer.
82
Revenues from services are recognized over time when the performance obligation is satisfied as services are provided in a series. We have elected to use the output measure of progress to recognize revenue based on the units delivered, processed or transported. The transaction prices in our Midstream contracts often have both fixed components, related to minimum volume commitments, and variable components, which are primarily dependent on volumes. Variable consideration will generally not be estimated at contract inception as the transaction price is specifically allocable to the services provided at each period end.
Refer to Note 20 for disclosure of our revenue disaggregated by segment and product line and to Note 10 for a description of our reportable segment operations.
Crude Oil and Refined Product Exchanges and Matching Buy/Sell Transactions
We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash. No revenues are recorded for exchange and matching buy/sell transactions as they are accounted for as exchanges of inventory. The exchange transactions are recognized at the carrying amount of the inventory transferred.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.
Accounts Receivable and Allowance for Expected Credit Loss
Our receivables primarily consist of customer accounts receivable. Customer receivables are recorded at the invoiced amounts and generally do not bear interest. Allowances for expected credit loss are generally recorded when it becomes probable the receivable will not be collected and are booked to bad debt expense. The allowance for expected credit loss is the best estimate of the amount of probable credit losses in customer accounts receivable. We review the allowance quarterly and past-due balances over 150 days are reviewed individually for collectability.
We mitigate credit risk with master netting agreements with companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry. A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.
Leases
Contracts with a term greater than one year that convey the right to direct the use of and obtain substantially all of the economic benefit of an asset are accounted for as right of use assets.
Right of use asset and lease liability balances are recorded at the commencement date at present value of the fixed lease payments using a secured incremental borrowing rate with a maturity similar to the lease term because our leases do not provide implicit rates. We have elected to include both lease and non-lease components in the present value of the lease payments for all lessee asset classes with the exception of our marine and third-party contractor service equipment leases. The lease component of the payment for the marine and equipment asset classes is determined using a relative standalone selling price. See Note 26 for additional disclosures about our lease contracts.
As a lessor under ASU No. 2016-02, Leases (“ASC 842”), MPLX may be required to reclassify existing operating leases to sales-type leases upon modification and related reassessment of the leases. See Note 26 for further information regarding our ongoing evaluation of the impacts of lease reassessments as modifications occur. The net investment in sales-type leases is recorded within receivables, net and other noncurrent assets on the consolidated balance sheets. These amounts are comprised of the present value of the sum of the future minimum lease payments representing the value of the lease receivable and the unguaranteed residual value of the lease assets. Management assesses the net investment in sales-type leases for recoverability quarterly.
Inventories
Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the LIFO method. Costs for crude oil and other feedstocks and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.
Fair Value
We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:
83
•Level 1 – inputs are based upon unadjusted quoted prices for identical instruments in active markets. Our Level 1 derivative assets and liabilities include exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Commodity derivatives are covered under master netting agreements with an unconditional right to offset. Collateral deposits in futures commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives are classified as Level 1.
•Level 2 – inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant inputs are observable in the market or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Where applicable, these models project future cash flows and discount the future amounts to a present value using market-based observable inputs including interest rate curves, credit spreads, and forward and spot prices for currencies. Our Level 2 investments include commercial paper, certificates of deposit, time deposits and corporate notes and bonds. Our Level 2 derivative assets and liabilities primarily include certain OTC contracts.
•Level 3 – inputs are generally unobservable and typically reflect management’s estimates of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore determined using model-based techniques, including option pricing models and discounted cash flow models. Our Level 3 assets and liabilities include goodwill, long-lived assets and intangible assets, when they are recorded at fair value due to an impairment charge and an embedded derivative liability relates to a natural gas purchase agreement embedded in a keep‑whole processing agreement. Unobservable inputs used in the models are significant to the fair values of the assets and liabilities.
Derivative Instruments
We use derivatives to economically hedge a portion of our exposure to commodity price risk and, historically, to interest rate risk. Our use of selective derivative instruments that assume market risk is limited. All derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value. Certain commodity derivatives are reflected on the consolidated balance sheets on a net basis by counterparty as they are governed by master netting agreements. Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions.
Derivatives not designated as accounting hedges
Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil, (4) the acquisition of ethanol for blending with refined products, (5) the sale of NGLs, (6) the purchase of natural gas, (7) the purchase of soybean oil and (8) the sale of propane. Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income.
Concentrations of credit risk
All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on an assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE, we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.
Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.
Changes in the design or nature of the activities of a VIE, or our involvement with a VIE, may require us to reconsider our conclusions on the entity’s status as a VIE and/or our status as the primary beneficiary. Such reconsideration requires significant
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judgment and understanding of the organization. This could result in the deconsolidation or consolidation of the affected subsidiary, which would have a significant impact on our financial statements.
Variable Interest Entities are discussed in Note 6.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, generally 10 to 40 years for refining and midstream assets, 25 years for office buildings and 4 to 7 years for other miscellaneous fixed assets. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset group and its eventual disposition is less than the carrying amount of the asset group, an impairment assessment is performed and the excess of the book value over the fair value of the asset group is recorded as an impairment loss.
When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.
Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment at the reporting unit level annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. If we determine, based on a qualitative assessment, that it is more likely than not that a reporting unit’s fair value exceeds its carrying amount, no further impairment testing is required. If we do not perform a qualitative assessment or if that assessment indicates that further impairment testing is required, the fair value of each reporting unit is determined using an income and/or market approach which is compared to the carrying value of the reporting unit. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss would be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The fair value under the income approach is calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future volumes, discount rates, and future capital requirements.
Amortization of intangibles with definite lives is calculated using the straight-line method, which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Intangibles not subject to amortization are tested for impairment annually and when circumstances indicate that the fair value is less than the carrying amount of the intangible. If the fair value is less than the carrying value, an impairment is recorded for the difference.
Major Maintenance Activities
Costs for planned turnaround and other major maintenance activities are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental Costs
Environmental expenditures for additional equipment that mitigates or prevents future contamination or improves environmental safety or efficiency of the existing assets are capitalized. We recognize remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with the completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.
Asset Retirement Obligations
The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. The majority of our recognized asset retirement liability relates to conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities. The remaining recognized asset retirement liability relates to other refining assets, certain pipelines and processing facilities and other related pipeline assets. The fair values recorded for such obligations are based on the most probable current cost projections.
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Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. The asset retirement obligations principally include the hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal, pipeline and processing assets.
Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances. As a result, we believe that generally these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.
Income Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.
Share-Based Compensation Arrangements
The fair value of stock options granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. The average expected life is based on our historical employee exercise behavior. The assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of our common stock historical volatility.
The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant. The fair value of performance awards granted to our employees is determined using a Monte Carlo valuation model, which is updated quarterly, with appropriate mark-to-market adjustments made.
Our share-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. Awards expected to vest are estimated using the historical data of our own employees. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned share-based compensation is charged to equity when restricted stock awards are granted. Compensation expense is recognized over the requisite service period and is adjusted if conditions of the restricted stock award are not met.
Business Combinations
We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date. Any excess or deficiency of the purchase consideration when compared to the fair value of the net tangible assets acquired, if any, is recorded as goodwill or gain from a bargain purchase. For material acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition date, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the date of the acquisition. Any adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. Acquisition-related costs are expensed as incurred in connection with each business combination.
Environmental Credits and Obligations
In order to comply with certain regulations, specifically the RFS requirements implemented by the EPA and the cap-and-trade emission reduction program and low carbon fuel standard implemented by state programs, we are required to reduce our emissions, blend certain levels of biofuels or obtain allowances or credits to offset the obligations created by our operations. In regard to each program, we record an asset, included in other current assets or other noncurrent assets on the consolidated balance sheets, for allowances or credits owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess allowances or credits as of the balance sheet date, if any, and the weighted average cost of those allowances or credits. We record a liability, included in other current liabilities or deferred credits and other liabilities
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on the consolidated balance sheets, when we are deficient allowances or credits based on the product of the deficient amount as of the balance sheet date, if any, and either the fixed contract price or the market price of the allowances or credits at the balance sheet date. The cost of allowances or credits used for compliance is reflected in cost of revenues on the consolidated statements of income. Any gains or losses on the sale or expiration of allowances or credits are classified as other income on the consolidated statements of income. Proceeds from the sale of allowances or credits are reported in investing activities - all other, net on the consolidated statements of cash flows.
3. Accounting Standards
Recently Adopted
ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures
In December 2023, the FASB issued this ASU to update income tax disclosure requirements to provide consistent categories and greater disaggregation of information in the rate reconciliation and to disaggregate income taxes paid by jurisdiction. This ASU is effective for fiscal years beginning after December 15, 2024. We adopted this ASU in 2025 and applied the amendments on a retrospective basis. The enhanced income tax disclosures are presented in Note 12 - Income Taxes and Note 21 - Supplemental Cash Flow Information.
Not Yet Adopted
ASU 2025-06, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40)
In September 2025, the FASB issued ASU 2025-06 to modernize the accounting for software costs that are accounted for under ASC 350-40 by removing all references to prescriptive and sequential software development stages and requiring entities to begin capitalizing software costs when both management has authorized and committed to the funding of the software project, and it is probable that the project will be completed and the software will be used to perform its intended function. The ASU also provides enhanced guidance on evaluating whether the probable-to-complete recognition threshold has been met. This ASU is effective for fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments in this ASU may be applied either (1) prospectively to all projects started in reporting periods after adoption, including in-process projects, (2) on a modified transition basis that is based on the status of the project and whether software costs were capitalized before the date of adoption, or (3) retrospectively to all prior periods presented in the financial statements. We will adopt this ASU on a prospective basis and do not expect material impacts to our capitalized software cost.
ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses
In November 2024, the FASB issued an ASU to require more detailed information about specified categories of expenses (purchases of inventory, employee compensation, depreciation, amortization, and depletion) included in certain expense captions presented on the face of the income statement. This ASU is effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments in this ASU may be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this ASU or (2) retrospectively to all prior periods presented in the financial statements. We are currently evaluating the impact this ASU will have on our disclosures.
4. Master Limited Partnership
We own the general partner and a majority limited partner interest in MPLX, which owns and operates crude oil and light product transportation and logistics infrastructure as well as gathering, processing and fractionation assets. We control MPLX through our ownership of the general partner interest and, as of December 31, 2025, we owned approximately 64 percent of the outstanding MPLX common units.
Unit Repurchase Program
On August 5, 2025, MPLX announced its board of directors approved a $1.0 billion unit repurchase authorization in addition to the $1.0 billion unit repurchase authorization announced on August 2, 2022. These unit 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 suspended, discontinued or restarted at any time.
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Total unit repurchases were as follows for the respective periods:
| (In millions, except per unit data) | 2025 | 2024 | 2023 | ||||||||||||||
| Number of common units repurchased | 8 | 8 | — | ||||||||||||||
| Cash paid for common units repurchased | $ | 400 | $ | 326 | $ | — | |||||||||||
| Average cost per unit | $ | 51.58 | $ | 43.04 | $ | — | |||||||||||
As of December 31, 2025, MPLX had approximately $1.12 billion remaining under its unit repurchase authorizations.
Series A Preferred Units
The Series A preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event, which is outside MPLX’s control. Therefore, they are presented as temporary equity in the mezzanine section of our consolidated balance sheets.
During the years ended December 31, 2024 and December 31, 2023, certain Series A preferred unitholders exercised their rights to convert their Series A preferred units into 21 million common units and 2 million common units, respectively. Approximately 6 million Series A preferred units were outstanding as of December 31, 2024. On February 11, 2025, MPLX exercised its right to convert the remaining outstanding Series A preferred units into common units.
For a summary of changes in the redeemable preferred balance, see the accompanying consolidated statements of equity and redeemable noncontrollable interest.
Redemption of the Series B Preferred Units
On February 15, 2023, MPLX exercised its right to redeem all of its 600,000 outstanding preferred units (the “Series B preferred units”). MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit. The final semi-annual distribution on the Series B preferred units was paid on February 15, 2023 in the usual manner.
The excess of the total redemption price of $600 million paid to Series B preferred unitholders over the carrying value of the Series B preferred units on the redemption date resulted in a $2 million net reduction to retained earnings.
Agreements
We have various long-term, fee-based commercial agreements with MPLX. Under these agreements, MPLX provides transportation, storage, distribution and marketing services to us. With certain exceptions, these agreements generally contain minimum volume commitments. These transactions are eliminated in consolidation but are reflected as intersegment transactions among our Refining & Marketing, Renewable Diesel and Midstream segments. We also have agreements with MPLX that establish fees for operational and management services provided between us and MPLX and for executive management services and certain general and administrative services provided by us to MPLX. These transactions are eliminated in consolidation but are reflected as intersegment transactions between corporate and our Midstream segment.
Noncontrolling Interest
As a result of equity transactions of MPLX, we are required to adjust non-controlling interest and additional paid-in capital. Changes in MPC’s additional paid-in capital resulting from changes in its ownership interest in MPLX were as follows:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Increase (decrease) due to change in ownership | $ | (88) | $ | 159 | $ | (4) | |||||||||||
| Tax impact | 74 | (55) | — | ||||||||||||||
| Increase (decrease) in MPC's additional paid-in capital, net of tax | $ | (14) | $ | 104 | $ | (4) | |||||||||||
5. Acquisitions and Other Transactions
Northwind Midstream Acquisition
On August 29, 2025, MPLX completed the acquisition of 100 percent of Northwind Delaware Holdings LLC ( “Northwind Midstream”) for $2.4 billion in cash (the “Northwind Midstream Acquisition”). 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 financed with a portion of the net proceeds from MPLX's $4.5 billion senior notes issuance in August 2025.
Northwind Midstream consists of over 200,000 dedicated acres, more than 200 miles of gathering pipelines, two in-service acid gas injection wells at 20 MMcf/d and a third permitted well that will bring its total capacity to 37 MMcf/d. At the time of acquisition, the system had 150 MMcf/d of sour gas treating capacity, with in-process expansion projects expected to increase capacity to
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over 400 MMcf/d by the second half of 2026. The system is partially supported by minimum volume commitments by regional producers.
The Northwind Midstream Acquisition was accounted for as a business combination requiring all Northwind Midstream assets and liabilities to be remeasured to fair value. The fair value of property, plant and equipment was based primarily on the cost approach. The fair value of the identifiable intangible assets was primarily based on the multi-period excess earnings method, which is an income approach. The intangible assets acquired are related to various commercial contracts with a weighted average amortization period of 15 years. The following table reflects our preliminary allocation of the $2.4 billion purchase price to the Northwind Midstream assets and liabilities, as well as measurement period adjustments since the acquisition date:
| As originally reported | Adjustments | As adjusted | |||||||||||||||
| (In millions) | |||||||||||||||||
| Cash and cash equivalents | $ | 17 | $ | — | $ | 17 | |||||||||||
| Receivables | 11 | — | 11 | ||||||||||||||
| Other current assets | 1 | — | 1 | ||||||||||||||
| Property, plant and equipment | 1,182 | (13) | 1,169 | ||||||||||||||
| Intangibles | 951 | — | 951 | ||||||||||||||
| Other noncurrent assets | 2 | — | 2 | ||||||||||||||
| Total assets acquired | 2,164 | (13) | 2,151 | ||||||||||||||
| Liabilities assumed: | |||||||||||||||||
| Accounts payable | 105 | 10 | 115 | ||||||||||||||
| Other current liabilities | 1 | — | 1 | ||||||||||||||
| Long-term operating lease liabilities | 1 | — | 1 | ||||||||||||||
| Total liabilities assumed | 107 | 10 | 117 | ||||||||||||||
| Total identifiable net assets | 2,057 | (23) | 2,034 | ||||||||||||||
| Goodwill | 356 | 23 | 379 | ||||||||||||||
| Fair value of net assets acquired | $ | 2,413 | $ | — | $ | 2,413 | |||||||||||
The allocation is subject to revision, as certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, the final valuation of property, plant and equipment and intangible assets acquired, which may impact the amount of goodwill recognized. The final valuation will be completed no later than one year from the acquisition date. The results for the acquired business are reported within our Midstream segment.
The purchase price allocation resulted in the recognition of $379 million in goodwill by our Midstream segment, all of which is deductible by MPLX for tax purposes. Goodwill represents the accelerated growth opportunities in the Permian using Northwind Midstream’s asset base, which is complementary and adjacent to MPLX’s existing Delaware basin natural gas system and offers optionality to direct volumes through our integrated system.
Pro forma financial information assuming the Northwind Midstream Acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.
Divestiture of Rockies Operations
On November 12, 2025, MPLX completed the sale of its Rockies gathering and processing operations (the “Rockies”) to a subsidiary of Harvest Midstream (“Harvest”) for $980 million in cash. The transaction resulted in a gain of $159 million, which is included in net gain on disposal of assets on the accompanying consolidated statements of income. The sale of these non-core gathering and processing assets did not represent a strategic shift that has or will have a material effect on our operations or financial results. Prior to the sale, the Rockies operations were included in our Midstream segment.
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, in exchange for cash proceeds of $427 million. MPC’s equity method investment in TAMH was 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, which is included in income from equity method investments on the accompanying consolidated statements of income.
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BANGL, LLC Acquisitions
BANGL, LLC (“BANGL”) owns and operates a NGL pipeline system that connects production in the Delaware and Midland basins to key demand centers along the Gulf Coast. On July 31, 2024, MPLX exercised its right of first offer under the BANGL joint venture agreement to purchase an additional 20 percent ownership interest in BANGL for $210 million in cash, which increased total ownership interest to 45 percent (the “2024 BANGL Transaction”). The purchase price of the additional 20 percent ownership interest in BANGL exceeded MPLX’s portion of the underlying net assets of the joint venture by approximately $156 million. Following the 2024 BANGL Transaction, MPLX’s investment in BANGL continued to be accounted for as an equity method investment.
On July 1, 2025, MPLX purchased the remaining 55 percent interest in BANGL for $703 million cash, plus an earnout provision of up to $275 million based on targeted EBITDA growth from 2026 to 2029 (the “BANGL Acquisition”). We recorded a liability for these contingent payments in the third quarter of 2025. See Note 17 for additional detail on the inputs used to measure the fair value of these contingent payments. 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 (the “BANGL Debt Repayment”).
Upon acquisition of the remaining 55 percent interest in BANGL, MPLX’s existing equity investment was remeasured to fair value resulting in the recognition of a $ gain, which is included in income from equity method investments within the accompanying consolidated statements of income. The fair value of the previously held equity method investment was estimated using an income approach, with significant valuation inputs including forecasted cash flows and discount rates ranging from to . 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 following table summarizes the purchase price consideration in connection with the BANGL Acquisition:
| (In millions) | |||||
| Total cash paid | $ | 703 | |||
| Fair value of contingent consideration as of acquisition date | 234 | ||||
| Total consideration | 937 | ||||
| Fair value of previously held equity interest | 766 | ||||
| Fair value of net assets acquired | $ | 1,703 | |||
The BANGL Acquisition was accounted for as a business combination requiring all BANGL assets and liabilities to be remeasured to fair value. The fair value of property, plant and equipment was determined using a combination of both the cost and income approach. The fair value of the identifiable intangible assets was primarily based on the multi-period excess earnings method, which is an income approach. The intangible asset acquired is related to a customer relationship with an amortization period of 11 years. The following table reflects our preliminary determination of the fair value of the BANGL assets and liabilities:
| (In millions) | July 1, 2025 | ||||
| Assets acquired: | |||||
| Cash and cash equivalents | $ | 18 | |||
| Other current assets | 4 | ||||
| Property, plant and equipment | 1,550 | ||||
| Intangibles | 77 | ||||
| Other noncurrent assets | 22 | ||||
| Total assets acquired | 1,671 | ||||
| Liabilities assumed: | |||||
| Long-term debt due within one year | 46 | ||||
| Other current liabilities | 42 | ||||
| Long-term debt | 610 | ||||
| Other long-term liabilities | 1 | ||||
| Total liabilities assumed | 699 | ||||
| Total identifiable net assets | 972 | ||||
| Goodwill | 731 | ||||
| Fair value of net assets acquired | $ | 1,703 | |||
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The allocation is subject to revision, as certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, the final valuation of property, plant and equipment and intangible assets acquired, which may impact the amount of goodwill recognized. The final valuation will be completed no later than one year from the acquisition date.
The purchase price allocation resulted in the recognition of $731 million in goodwill by our Midstream segment, 55 percent of which is deductible by MPLX for tax purposes. Goodwill represents the advancement of MPLX’s wellhead-to-water strategy by securing full ownership of a strategically located NGL transport asset which further integrates MPLX’s midstream infrastructure connecting the Permian and Gulf Coast regions.
Pro forma financial information assuming the BANGL Acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.
Whiptail Midstream Acquisition
On March 11, 2025, MPLX acquired gathering businesses from Whiptail Midstream, LLC for $235 million in cash. 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, which requires all the identifiable assets acquired and liabilities assumed to be remeasured to fair value at the date of acquisition. The final valuation includes $170 million of property, plant and equipment, $41 million of intangibles and $24 million of net working capital. The results for the acquired business are reported within our Midstream segment.
Jones Act Blue Water Vessels Acquisition
Marathon Coastal Holdings LLC (formerly known as Crowley Coastal Partners LLC, “Coastal Holdings”) was formed in May 2016 as a joint venture to own, through its subsidiaries, four Jones Act mid-range product tankers and three Jones Act series 750 ATB vessels. Prior to October 1, 2024, MPC accounted for our 50 percent ownership in Coastal Holdings as an equity method investment.
On October 1, 2024, MPC paid approximately $66 million in cash to purchase the remaining 50 percent interest in Coastal Holdings and its subsidiary, Marathon Blue Water Holdings LLC (formerly known as Crowley Blue Water Partners, LLC, “Blue Water Holdings”), which owns the three ATB vessels, from our joint venture partner. As part of the transaction, MPC assumed Blue Water Holdings’ United States Maritime Administration guaranteed obligations (the “MARAD Debt”) with an aggregate outstanding principal amount and accrued interest value of $175 million as of October 1, 2024. See Note 19 for additional information. Subsequent to the acquisition date, Coastal Holdings is wholly owned by MPC and is included in our consolidated results.
The excess of the $66 million fair value over the $50 million book value of our 50 percent indirect interest in Coastal Holdings resulted in a $16 million gain, which is included in income from equity method investments on the accompanying consolidated statements of income.
Whistler Joint Venture Transaction
On May 29, 2024, MPLX and its joint venture partner contributed their respective membership interests in Whistler Pipeline, LLC to a newly formed joint venture, WPC Parent, LLC, and issued 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”). As a result of the transaction, MPLX’s voting interest in the joint venture was reduced from 37.5 percent to 30.4 percent. MPLX recognized a gain of $151 million at closing and received a cash distribution of $134 million, recorded as a return of capital, related to the dilution of the ownership interest. The gain is included in income from equity method investments on the accompanying consolidated statements of income and the return of capital is included in investments - redemptions, repayments, return of capital and sales proceeds within the investing section of the accompanying consolidated statements of cash flows.
Utica Midstream Acquisition
On March 22, 2024, MPLX used $625 million of cash to purchase additional ownership interests in existing joint ventures and gathering assets, which will enhance MPLX’s position in the Utica basin. Prior to the acquisition, MPLX owned an indirect interest in Ohio Gathering Company, L.L.C. (“OGC”) and a direct interest in Ohio Condensate Company, L.L.C. (“OCC”). After giving effect to the acquisition, MPLX owns a combined direct and indirect 73 percent interest in OGC and a 100 percent interest in OCC. In addition, MPLX acquired a 100 percent interest in a dry gas gathering system in the Utica basin. OGC continues to be accounted for as an equity method investment as MPLX did not obtain control of OGC as a result of the transaction. OGC is considered a VIE and MPLX is not deemed to be the primary beneficiary due to voting rights on significant matters. The acquisition date fair value of our investment in OGC exceeded our portion of the underlying net assets of the joint venture by approximately $75 million. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets. OCC was previously accounted for as an equity method investment, and it is now consolidated and included in our consolidated financial results.
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The acquisition was accounted for as a business combination requiring all the acquired assets and liabilities to be remeasured to fair value resulting in a consolidated fair value of net assets and liabilities of $625 million. The fair value includes $507 million related to acquired interests in the joint ventures and the remaining balance related to other acquired assets and liabilities. The revaluation of MPLX’s existing 62 percent equity method investment in OCC resulted in a $20 million gain, which is included in net gain on disposal of assets on the accompanying consolidated statements of income. The fair value of equity method investments was based on a discounted cash flow model.
MarkWest Torñado GP, L.L.C. Acquisition
On December 15, 2023, MPLX used $303 million of cash on hand to purchase the remaining 40 percent interest in MarkWest Torñado GP, L.L.C. (“Torñado”) for approximately $270 million, including cash paid for working capital, and to extend the term of a gathering and processing agreement for approximately $33 million. As a result of this transaction, this entity is now consolidated and included in our consolidated financial results. It was previously accounted for as an equity method investment. Torñado provides natural gas gathering and processing related services in the Permian basin. The results for this business are reported within our Midstream segment.
At December 15, 2023, the carrying value of MPLX’s 60 percent equity investment in Torñado was $311 million. Upon acquisition of the remaining 40 percent member interest, the existing equity investment was remeasured to fair value resulting in the recognition of a $92 million gain, which was presented in the net gain on disposal of assets line on the accompanying consolidated statements of income. The fair value of the previously held equity method investment was primarily based on the price negotiated for the 40 percent interest in Torñado.
The acquisition was accounted for as a business combination. While the purchase price for the 40 percent interest was $270 million, all of the Torñado assets and liabilities were remeasured to fair value resulting in a consolidated fair value of net assets and liabilities of $673 million, consisting primarily of property, plant and equipment and identifiable intangible assets. The fair value of property, plant and equipment was based primarily on the cost approach. The fair value of the identifiable intangible assets, consisting of various customer contracts, was primarily based on the multi-period excess earnings method, which is an income approach.
South Texas Gateway Terminal LLC Sale
On August 1, 2023, MPC sold its 25 percent interest in South Texas Gateway Terminal LLC (“South Texas Gateway”) to an affiliate of Gibson Energy Inc. (“Gibson Energy”). Gibson Energy paid $1.1 billion in cash to acquire 100 percent of the membership interests of South Texas Gateway from MPC and its other members. South Texas Gateway owns an oil export facility in the U.S. Gulf Coast. MPC’s proceeds were $270 million, resulting in a gain of $106 million, which is included in net gain on disposal of assets on the accompanying consolidated statements of income.
LF Bioenergy Acquisition
On March 8, 2023, MPC announced the acquisition of a 49.9 percent interest in LF Bioenergy, an emerging producer of renewable natural gas (“RNG”) in the U.S., for approximately $56 million, which included funding for on-going operations and project development. LF Bioenergy has been focused on developing and growing a portfolio of dairy farm-based, low carbon intensity RNG projects. MPC accounts for our ownership interest in LF Bioenergy as an equity method investment.
6. Variable Interest Entities
Consolidated VIE
We control MPLX through our ownership of its general partner. MPLX is a VIE because the limited partners do not have substantive kick-out or participating rights over the general partner. We are the primary beneficiary of MPLX because in addition to our significant economic interest, we also have the ability, through our ownership of the general partner, to control the decisions that most significantly impact MPLX. We therefore consolidate MPLX and record a noncontrolling interest for the interest owned by the public.
The creditors of MPLX do not have recourse to MPC’s general credit or assets through guarantees or other financial arrangements, except as otherwise noted. MPC has effectively guaranteed certain indebtedness of LOOP LLC (“LOOP”) and LOCAP LLC (“LOCAP”), in which MPLX holds an interest. See Note 27 for more information. The assets of MPLX can only be used to settle its own obligations and any rights of MPC’s creditors to participate in the assets of MPLX are subject to prior claims of MPLX’s creditors.
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The following table presents balance sheet information for the assets and liabilities of MPLX, which are included in our consolidated balance sheets.
| (Millions of dollars) | December 31, 2025 | December 31, 2024 | |||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | 2,137 | $ | 1,519 | |||||||
| Receivables, less allowance for expected credit loss | 746 | 731 | |||||||||
| Inventories | 172 | 180 | |||||||||
| Other current assets | 51 | 29 | |||||||||
| Equity method investments | 4,798 | 4,531 | |||||||||
| Property, plant and equipment, net | 21,698 | 19,154 | |||||||||
| Goodwill | 8,755 | 7,645 | |||||||||
| Intangibles, net | 1,397 | 518 | |||||||||
| Right of use assets, net | 276 | 273 | |||||||||
| Other noncurrent assets | 1,126 | 995 | |||||||||
| Liabilities | |||||||||||
| Accounts payable | $ | 865 | $ | 719 | |||||||
| Accrued taxes | 93 | 82 | |||||||||
| Debt due within one year | 1,502 | 1,693 | |||||||||
| Operating lease liabilities | 53 | 45 | |||||||||
| Other current liabilities | 403 | 370 | |||||||||
| Long-term debt | 24,151 | 19,255 | |||||||||
| Deferred income taxes | 25 | 18 | |||||||||
| Long-term operating lease liabilities | 217 | 217 | |||||||||
| Deferred credits and other liabilities | 474 | 445 | |||||||||
Non-Consolidated VIEs
Martinez Renewables LLC
On September 21, 2022, MPC closed on the formation of the Martinez Renewables LLC joint venture. We determined that Martinez Renewables LLC is a VIE because the entity does not have sufficient equity to operate without additional financial support from its owners. We are not the primary beneficiary of this VIE because we do not have the ability to control the activities that significantly influence the economic outcomes of the entity and, therefore, do not consolidate the entity.
MPLX VIEs
For those entities that have been deemed to be VIEs, neither MPLX nor any of its subsidiaries have been deemed to be the primary beneficiary due to voting rights on significant matters. While we have the ability to exercise influence through participation in the management committees which make all significant decisions, we have equal influence over each committee as a joint interest partner and all significant decisions require the consent of the other investors without regard to economic interest and as such we have determined that these entities should not be consolidated and apply the equity method of accounting with respect to our investments in each entity.
Sherwood Midstream LLC (“Sherwood Midstream”) has been deemed the primary beneficiary of Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”) due to its controlling financial interest through its authority to manage the joint venture. As a result, Sherwood Midstream consolidates Sherwood Midstream Holdings.
MPLX’s maximum exposure to loss as a result of its involvement with equity method investments includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services.
We account for our ownership interest in each of these investments as an equity method investment. See Note 14 for ownership percentages and investment balances.
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7. Related Party Transactions
Transactions with related parties were as follows:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Sales to related parties | $ | 1,572 | $ | 1,053 | $ | 915 | |||||||||||
| Purchases from related parties | 2,891 | 2,437 | 1,818 | ||||||||||||||
Sales to related parties, which are included in sales and other operating revenues, consist primarily of refined product sales and renewable feedstock sales to certain of our equity affiliates.
Purchases from related parties are included in cost of revenues. We obtain utilities, transportation services and purchase renewable diesel from certain of our equity affiliates.
We also purchased ethanol from TAMH, an equity affiliate. On July 31, 2025, MPC sold its interest in TAMH. TAMH ceased to be a related party after the sale. See Note 5.
8. Earnings Per Share
We compute basic earnings per share by dividing net income attributable to MPC less income allocated to participating securities by the weighted average number of shares of common stock outstanding. Since MPC has granted certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities, we have calculated our earnings per share using the two-class method. Diluted income per share assumes exercise of certain share-based compensation awards, provided the effect is not anti-dilutive.
| (In millions, except per share data) | 2025 | 2024 | 2023 | ||||||||||||||
| Basic earnings per share: | |||||||||||||||||
| Allocation of earnings | |||||||||||||||||
| Net income attributable to MPC | $ | 4,047 | $ | 3,445 | $ | 9,681 | |||||||||||
| Income allocated to participating securities | (4) | (3) | (7) | ||||||||||||||
| Redemption of preferred units | — | — | (2) | ||||||||||||||
| Income available to common stockholders - basic | $ | 4,043 | $ | 3,442 | $ | 9,672 | |||||||||||
| Weighted average common shares outstanding | 305 | 340 | 407 | ||||||||||||||
| Basic earnings per share | $ | 13.24 | $ | 10.11 | $ | 23.73 | |||||||||||
| Diluted earnings per share: | |||||||||||||||||
| Allocation of earnings | |||||||||||||||||
| Net income attributable to MPC | $ | 4,047 | $ | 3,445 | $ | 9,681 | |||||||||||
| Income allocated to participating securities | (4) | (3) | (7) | ||||||||||||||
| Redemption of preferred units | — | — | (2) | ||||||||||||||
| Income available to common stockholders - diluted | 4,043 | 3,442 | 9,672 | ||||||||||||||
| Weighted average common shares outstanding | 305 | 340 | 407 | ||||||||||||||
| Effect of dilutive securities | 1 | 1 | 2 | ||||||||||||||
| Weighted average common shares, including dilutive effect | 306 | 341 | 409 | ||||||||||||||
| Diluted earnings per share | $ | 13.22 | $ | 10.08 | $ | 23.63 | |||||||||||
Potential common shares which were anti-dilutive and, therefore, omitted from the diluted share calculation, were immaterial for all periods.
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9. Equity
On November 5, 2024, MPC announced that our board of directors approved a $5.0 billion share repurchase authorization. Share repurchase authorizations since 2012 totaled $60.05 billion. As of December 31, 2025, $4.38 billion remained available for repurchase under the share repurchase authorization. The share repurchase authorization has no expiration date.
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, discontinued or restarted at any time.
Total share repurchases were as follows for the respective periods:
| (In millions, except per share data) | 2025 | 2024 | 2023 | ||||||||||||||
| Number of shares repurchased | 21 | 53 | 89 | ||||||||||||||
Cash paid for shares repurchased(a) | $ | 3,399 | $ | 9,077 | $ | 11,572 | |||||||||||
Average cost per share(b) | $ | 163.64 | $ | 171.68 | $ | 131.27 | |||||||||||
(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.
10. Segment Information
We have three reportable segments: Refining & Marketing, Midstream and Renewable Diesel. Each of these segments is organized and managed based upon the nature of the products and services it offers.
•Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast, Mid-Continent and West Coast regions of the United States, purchases refined products and ethanol for resale and distributes refined products through transportation, storage, distribution and marketing services provided largely by our Midstream segment. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to independent entrepreneurs who operate primarily Marathon® branded outlets and through long-term supply contracts with direct dealers who operate locations mainly under the ARCO® brand.
•Midstream – gathers, transports, stores and distributes crude oil, refined products, including renewable diesel, and other hydrocarbon-based products principally for the Refining & Marketing segment via refining logistics assets, pipelines, terminals, towboats and barges; gathers, treats, processes and transports natural gas; and transports, fractionates, stores and markets NGLs. The Midstream segment primarily reflects the results of MPLX.
•Renewable Diesel - processes renewable feedstocks into renewable diesel, markets renewable diesel and distributes renewable products through our Midstream segment and third parties. We sell renewable diesel to wholesale marketing customers, to buyers on the spot market and through long-term supply contracts with direct dealers who operate locations mainly under the ARCO® brand.
Our chief operating decision maker (“CODM”) evaluates the performance of our segments using segment adjusted EBITDA. Our CODM is our chief executive officer. The CODM uses adjusted EBITDA by segment results and considers forecast-to-actual variances on a periodic basis when making decisions about allocating capital and personnel as part of the annual business plan process and ongoing monitoring of performance. Amounts included in income before income taxes and excluded from 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) not tied to the operational performance of the segment. Assets by segment are not a measure used to assess the performance of the company by the CODM and thus are not reported in our disclosures.
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| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Segment adjusted EBITDA for reportable segments | |||||||||||||||||
| Refining & Marketing | 6,138 | $ | 5,703 | $ | 13,705 | ||||||||||||
| Midstream | 6,750 | 6,544 | 6,171 | ||||||||||||||
| Renewable Diesel | (110) | (150) | (64) | ||||||||||||||
| Total reportable segments | $ | 12,778 | $ | 12,097 | $ | 19,812 | |||||||||||
| Reconciliation of segment adjusted EBITDA for reportable segments to income before income taxes | |||||||||||||||||
| Total reportable segments | $ | 12,778 | $ | 12,097 | $ | 19,812 | |||||||||||
| Corporate | (822) | (774) | (737) | ||||||||||||||
| Refining & Renewable Diesel planned turnaround costs | (1,553) | (1,404) | (1,201) | ||||||||||||||
Renewable Diesel JV planned turnaround costs(a) | (18) | (9) | (25) | ||||||||||||||
| Garyville incident response costs | — | — | (16) | ||||||||||||||
| LIFO inventory adjustment | 72 | 161 | (145) | ||||||||||||||
Gain on sale of assets(b) | 897 | 151 | 198 | ||||||||||||||
| SRE | 57 | — | — | ||||||||||||||
Transaction-related costs(c) | (33) | — | — | ||||||||||||||
| Legal settlements | 253 | — | — | ||||||||||||||
| Depreciation and amortization | (3,251) | (3,337) | (3,307) | ||||||||||||||
Renewable Diesel JV depreciation and amortization(a) | (89) | (89) | (65) | ||||||||||||||
| Net interest and other financial costs | (1,276) | (839) | (525) | ||||||||||||||
| Income before income taxes | $ | 7,015 | $ | 5,957 | $ | 13,989 | |||||||||||
(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 sale of MPC’s interest in TAMH and the Rockies divestiture. 2024 includes the gain from the Whistler Joint Venture Transaction. 2023 includes the gain associated with the remeasurement of MPLX’s existing equity investment in MarkWest Torñado GP, L.L.C., arising from the acquisition of the remaining 40 percent interest and the gain on the sale of our interest in South Texas Gateway Terminal LLC. See Note 5 for additional information.
(c) Transaction-related costs include costs associated with the Northwind Midstream Acquisition, the BANGL Acquisition and the Rockies divestiture discussed in Note 5.
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Sales and other operating revenues | |||||||||||||||||
| Refining & Marketing | |||||||||||||||||
Revenues from external customers(a) | $ | 124,252 | $ | 131,588 | $ | 141,835 | |||||||||||
| Intersegment revenues | 60 | 175 | 139 | ||||||||||||||
| Refining & Marketing segment revenues | 124,312 | 131,763 | 141,974 | ||||||||||||||
| Midstream | |||||||||||||||||
Revenues from external customers(a) | 5,628 | 5,197 | 4,911 | ||||||||||||||
| Intersegment revenues | 5,906 | 5,797 | 5,597 | ||||||||||||||
| Midstream segment revenues | 11,534 | 10,994 | 10,508 | ||||||||||||||
| Renewable Diesel | |||||||||||||||||
Revenues from external customers(a) | 2,814 | 2,079 | 1,633 | ||||||||||||||
| Intersegment revenues | 16 | 25 | 31 | ||||||||||||||
| Renewable Diesel segment revenues | 2,830 | 2,104 | 1,664 | ||||||||||||||
| Total segment revenues | 138,676 | 144,861 | 154,146 | ||||||||||||||
| Plus: other revenue | 5 | — | — | ||||||||||||||
| Less: intersegment revenues | 5,982 | 5,997 | 5,767 | ||||||||||||||
Consolidated sales and other operating revenues(a) | $ | 132,699 | $ | 138,864 | $ | 148,379 | |||||||||||
(a) Includes sales to related parties. See Note 7 for additional information. See Note 20 for the disaggregation of our revenue from external customers by segment and product line.
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| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Income from equity method investments | |||||||||||||||||
| Refining & Marketing | $ | 9 | $ | 57 | $ | 66 | |||||||||||
| Midstream | 793 | 770 | 735 | ||||||||||||||
| Renewable Diesel | 82 | 70 | (59) | ||||||||||||||
| Total segment income from equity method investments | 884 | 897 | 742 | ||||||||||||||
Corporate(a) | 738 | 151 | — | ||||||||||||||
| Consolidated income from equity method investments | $ | 1,622 | $ | 1,048 | $ | 742 | |||||||||||
(a) 2025 includes gains from the BANGL Acquisition and the sale of MPC’s interest in TAMH. 2024 represents the gain from the Whistler Joint Venture Transaction. See Note 5 for additional information.
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Segment expenses | |||||||||||||||||
| Refining & Marketing | |||||||||||||||||
| Cost of purchases | $ | 104,308 | $ | 112,938 | $ | 115,973 | |||||||||||
| Refining operating costs | 6,097 | 5,712 | 5,625 | ||||||||||||||
| Distribution costs | 6,185 | 5,857 | 5,645 | ||||||||||||||
Other segment items(a) | 1,593 | 1,610 | 1,092 | ||||||||||||||
| Refining & Marketing segment expenses | $ | 118,183 | $ | 126,117 | $ | 128,335 | |||||||||||
| Midstream | |||||||||||||||||
Other segment items(b) | 5,577 | 5,220 | 5,072 | ||||||||||||||
| Midstream segment expenses | $ | 5,577 | $ | 5,220 | $ | 5,072 | |||||||||||
| Renewable Diesel | |||||||||||||||||
| Operating costs | 274 | 269 | 242 | ||||||||||||||
| Distribution costs | 101 | 95 | 82 | ||||||||||||||
Other segment items(c) | 2,647 | 1,960 | 1,345 | ||||||||||||||
| Renewable Diesel segment expenses | $ | 3,022 | $ | 2,324 | $ | 1,669 | |||||||||||
(a) Other segment items for the Refining & Marketing segment include costs that are reimbursed by customers through commercial arrangements, as well as LIFO inventory adjustments.
(b) Other segment items for the Midstream segment include operating expenses and purchased product costs. For purposes of managing Midstream segment of MPC, the CODM is only provided consolidated Midstream expense information.
(c) Other segment items for the Renewable Diesel segment include purchased product costs.
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Depreciation and amortization | |||||||||||||||||
| Refining & Marketing | $ | 1,627 | $ | 1,767 | $ | 1,822 | |||||||||||
| Midstream | 1,450 | 1,405 | 1,320 | ||||||||||||||
Renewable Diesel(a) | 69 | 75 | 65 | ||||||||||||||
| Total segment depreciation and amortization | 3,146 | 3,247 | 3,207 | ||||||||||||||
| Corporate | 105 | 90 | 100 | ||||||||||||||
| Consolidated depreciation and amortization | $ | 3,251 | $ | 3,337 | $ | 3,307 | |||||||||||
(a) Excludes our pro-rata share of Renewable Diesel JV depreciation and amortization of $89 million, $89 million and $65 million in 2025, 2024 and 2023, respectively, which was adjusted for purposes of arriving at Renewable Diesel segment adjusted EBITDA.
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| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Capital expenditures | |||||||||||||||||
| Refining & Marketing | $ | 1,580 | $ | 1,445 | $ | 998 | |||||||||||
| Midstream | 2,975 | 1,504 | 1,105 | ||||||||||||||
| Renewable Diesel | 19 | 8 | 313 | ||||||||||||||
| Total segment capital expenditures and investments | 4,574 | 2,957 | 2,416 | ||||||||||||||
| Less investments in equity method investees | 1,064 | 509 | 480 | ||||||||||||||
| Plus: | |||||||||||||||||
| Corporate | 25 | 63 | 83 | ||||||||||||||
| Capitalized interest | 94 | 56 | 55 | ||||||||||||||
Consolidated capital expenditures(a) | $ | 3,629 | $ | 2,567 | $ | 2,074 | |||||||||||
(a) Includes changes in capital expenditure accruals. See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.
No single customer accounted for 10 percent or more of annual revenues for the years ended December 31, 2025, December 31, 2024 or December 31, 2023. See Note 20 for the disaggregation of our revenue by segment and product line.
We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-lived assets located in foreign countries, including property, plant and equipment and investments, are not material to our operations.
11. Net Interest and Other Financial Costs
Net interest and other financial costs were as follows:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Interest income | $ | (159) | $ | (376) | $ | (530) | |||||||||||
| Interest expense | 1,489 | 1,365 | 1,325 | ||||||||||||||
| Interest capitalized | (100) | (57) | (60) | ||||||||||||||
Pension and other postretirement non-service costs(a) | 23 | (38) | (89) | ||||||||||||||
| Investments - net premium (discount) amortization | — | (91) | (142) | ||||||||||||||
| Other financial costs | 23 | 36 | 21 | ||||||||||||||
| Net interest and other financial costs | $ | 1,276 | $ | 839 | $ | 525 | |||||||||||
(a) See Note 24.
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12. Income Taxes
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Income (loss) from operations before income taxes: | |||||||||||||||||
| Domestic | $ | 6,958 | $ | 5,964 | $ | 13,875 | |||||||||||
| Foreign | 57 | (7) | 114 | ||||||||||||||
| Total | $ | 7,015 | $ | 5,957 | $ | 13,989 | |||||||||||
| Provision (benefit) for income taxes: | |||||||||||||||||
| Current: | |||||||||||||||||
| Federal | $ | 706 | $ | 862 | $ | 2,359 | |||||||||||
| State and local | 129 | 144 | 475 | ||||||||||||||
| Foreign | 20 | 8 | 11 | ||||||||||||||
| Total current | 855 | 1,014 | 2,845 | ||||||||||||||
| Deferred: | |||||||||||||||||
| Federal | 255 | (90) | 18 | ||||||||||||||
| State and local | 25 | (33) | (46) | ||||||||||||||
| Foreign | 2 | (1) | — | ||||||||||||||
| Total deferred | 282 | (124) | (28) | ||||||||||||||
| Total | $ | 1,137 | $ | 890 | $ | 2,817 | |||||||||||
A reconciliation of the federal statutory income tax rate to the effective tax rate applied to income from before income taxes follows:
| 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||||||
| (Millions of dollars) | Amount | % | Amount | % | Amount | % | |||||||||||||||||||||||||||||
| Federal statutory rate | $ | 1,473 | 21.0 | % | $ | 1,251 | 21.0 | % | $ | 2,937 | 21.0 | % | |||||||||||||||||||||||
State and local income taxes, net of federal income tax effects(a) | 128 | 1.8 | 91 | 1.5 | 338 | 2.4 | |||||||||||||||||||||||||||||
| Nontaxable or nondeductible items: | |||||||||||||||||||||||||||||||||||
| Noncontrolling interests | (385) | (5.5) | (341) | (5.7) | (314) | (2.2) | |||||||||||||||||||||||||||||
| Other | 24 | 0.3 | (44) | (0.8) | (30) | (0.3) | |||||||||||||||||||||||||||||
| Tax credits | (84) | (1.2) | (42) | (0.7) | — | — | |||||||||||||||||||||||||||||
| Other adjustments | (19) | (0.2) | (25) | (0.4) | (114) | (0.8) | |||||||||||||||||||||||||||||
| Effective tax rate applied to income before income taxes | $ | 1,137 | 16.2 | % | $ | 890 | 14.9 | % | $ | 2,817 | 20.1 | % | |||||||||||||||||||||||
(a) State taxes in California, Texas and Kentucky make up the majority of the tax effect of this category.
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Deferred tax assets and liabilities resulted from the following:
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Deferred tax assets: | |||||||||||
| Employee benefits | $ | 560 | $ | 558 | |||||||
| Environmental remediation | 80 | 81 | |||||||||
| Finance lease obligations | 409 | 433 | |||||||||
| Operating lease liabilities | 314 | 243 | |||||||||
| Net operating loss carryforwards | 32 | 39 | |||||||||
| Tax credit carryforwards | 20 | 22 | |||||||||
| Goodwill and other intangibles | 84 | 75 | |||||||||
| Other | 115 | 95 | |||||||||
| Total deferred tax assets | 1,614 | 1,546 | |||||||||
| Valuation allowance | (9) | (51) | |||||||||
| Total net deferred tax assets | 1,605 | 1,495 | |||||||||
| Deferred tax liabilities: | |||||||||||
| Property, plant and equipment | 2,441 | 2,584 | |||||||||
| Inventories | 845 | 672 | |||||||||
| Investments in subsidiaries and affiliates | 3,957 | 3,742 | |||||||||
| Right of use assets | 324 | 246 | |||||||||
| Other | 19 | 20 | |||||||||
| Total deferred tax liabilities | 7,586 | 7,264 | |||||||||
| Net deferred tax liabilities | $ | 5,981 | $ | 5,769 | |||||||
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Assets: | |||||||||||
| Other noncurrent assets | $ | 3 | $ | 2 | |||||||
| Liabilities: | |||||||||||
| Deferred income taxes | 5,984 | 5,771 | |||||||||
| Net deferred tax liabilities | $ | 5,981 | $ | 5,769 | |||||||
At December 31, 2025 and 2024, federal operating loss carryforwards were $2 million and $3 million, respectively, which includes a mix of indefinite carryforward ability and expiration periods ranging from 2032 through 2034. As of December 31, 2025 and 2024, state and local operating loss and tax credit carryforwards were $38 million and $42 million, respectively, which includes a mix of indefinite carryforward ability and expiration periods ranging from 2029 through 2045. At December 31, 2025 and 2024, foreign operating loss carryforwards were $12 million and $16 million, respectively, which includes expiration periods ranging from 2031 through 2043.
As of December 31, 2025 and 2024, $9 million and $51 million of valuation allowances have been recorded related to income taxes, related to realizability of foreign tax operating losses, state tax net operating losses and credits, and related deferred tax assets.
MPC is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service (“IRS”). Since 2012, we have continued to participate in the Compliance Assurance Process (“CAP”). CAP is a real-time audit of the U.S. federal income tax return that allows the IRS, working in conjunction with MPC, to determine tax return compliance with the U.S. federal tax law prior to filing the return. This program provides us with greater certainty about our tax liability for years under examination by the IRS. MPLX and its subsidiaries are undergoing examination of its U.S. federal income tax returns by the IRS for the tax years 2019 through 2022. We do not believe the eventual outcome of such audits will have a material impact on our financial statements as of December 31, 2025.
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Further, we are routinely involved in U.S. state income tax audits. We believe all other audits will be resolved with the amounts provided for these liabilities. As of December 31, 2025, we have various state and local income tax returns subject to examination for years 2016 through 2023, depending on jurisdiction.
The following table summarizes the activity in unrecognized tax benefits:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| January 1 balance | $ | 27 | $ | 38 | $ | 57 | |||||||||||
| Additions for tax positions of current year | 80 | — | — | ||||||||||||||
| Additions for tax positions of prior years | 65 | — | 8 | ||||||||||||||
| Reductions for tax positions of prior years | (7) | (5) | (6) | ||||||||||||||
| Settlements | (2) | (6) | (20) | ||||||||||||||
| Statute of limitations | — | — | (1) | ||||||||||||||
| December 31 balance | $ | 163 | $ | 27 | $ | 38 | |||||||||||
If the unrecognized tax benefits as of December 31, 2025 were recognized, $82 million would affect our effective income tax rate.
Interest and penalties related to income taxes are recorded as part of the provision for income taxes.
13. Inventories
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Crude oil and other feedstocks | $ | 3,272 | $ | 3,185 | |||||||
| Refined products | 5,350 | 5,137 | |||||||||
| Materials and supplies | 1,507 | 1,246 | |||||||||
| Total | $ | 10,129 | $ | 9,568 | |||||||
The cost of inventories of crude oil and other feedstocks and refined products is determined under the LIFO method. The LIFO method accounted for 85 percent and 87 percent of total inventory value at December 31, 2025 and December 31, 2024, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2025 and 2024 by $959 million and $2.53 billion, respectively.
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14. Equity Method Investments
| Ownership as of | Carrying value at | ||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| (In millions of dollars, except ownership percentages) | VIE | 2025 | 2025 | 2024 | |||||||||||||||||||
| Refining & Marketing | |||||||||||||||||||||||
TAMH(a) | —% | $ | — | $ | 190 | ||||||||||||||||||
LF Bioenergy Holdings LLC | 50% | 98 | 92 | ||||||||||||||||||||
| Refining & Marketing Total | $ | 98 | $ | 282 | |||||||||||||||||||
| Midstream | |||||||||||||||||||||||
| MPLX | |||||||||||||||||||||||
BANGL(b) | $ | — | $ | 281 | |||||||||||||||||||
| Illinois Extension Pipeline Company, L.L.C. | 35% | 208 | 218 | ||||||||||||||||||||
| LOOP LLC | 41% | 313 | 310 | ||||||||||||||||||||
| MarEn Bakken Company LLC | 25% | 502 | 526 | ||||||||||||||||||||
| MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. | X | 67% | 407 | 329 | |||||||||||||||||||
| MarkWest Utica EMG, L.L.C. | X | 61% | 890 | 742 | |||||||||||||||||||
| Ohio Gathering Co, LLC | X | 32% | 444 | 470 | |||||||||||||||||||
| Sherwood Midstream LLC | X | 50% | 475 | 488 | |||||||||||||||||||
| Texas City Logistics LLC | X | 50% | 163 | — | |||||||||||||||||||
| WPC Parent, LLC | 30% | 273 | 208 | ||||||||||||||||||||
Other(c) | X | 1,123 | 959 | ||||||||||||||||||||
| MPLX Total | $ | 4,798 | $ | 4,531 | |||||||||||||||||||
| MPC-Retained | |||||||||||||||||||||||
| Capline Pipeline Company LLC | 33% | $ | 365 | $ | 382 | ||||||||||||||||||
| Gray Oak Pipeline, LLC | 25% | 268 | 274 | ||||||||||||||||||||
Other(c) | X | 113 | 114 | ||||||||||||||||||||
| MPC-Retained Total | $ | 746 | $ | 770 | |||||||||||||||||||
| Midstream Total | $ | 5,544 | $ | 5,301 | |||||||||||||||||||
| Renewable Diesel | |||||||||||||||||||||||
| Martinez Renewables LLC | X | 50% | $ | 1,065 | $ | 1,184 | |||||||||||||||||
Other(c) | X | 88 | 90 | ||||||||||||||||||||
| Renewable Diesel Total | $ | 1,153 | $ | 1,274 | |||||||||||||||||||
| Total | $ | 6,795 | $ | 6,857 | |||||||||||||||||||
(a) In July 2025, we sold our interest in TAMH, as discussed in Note 5.
(b) In July 2025, MPLX purchased the remaining interest in BANGL, increasing MPLX’s ownership to 100 percent. See Note 5 for additional information.
(c) Some investments included within “Other” have been deemed to be VIEs.
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Summarized financial information for all equity method investments in affiliated companies, combined, was as follows:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Income statement data: | |||||||||||||||||
| Revenues and other income | $ | 10,223 | $ | 9,259 | $ | 6,544 | |||||||||||
| Income from operations | 2,713 | 2,698 | 2,428 | ||||||||||||||
| Net income | 2,368 | 2,211 | 2,089 | ||||||||||||||
| Balance sheet data – December 31: | |||||||||||||||||
| Current assets | $ | 2,246 | $ | 2,687 | |||||||||||||
| Noncurrent assets | 26,310 | 24,656 | |||||||||||||||
| Current liabilities | 2,176 | 1,927 | |||||||||||||||
| Noncurrent liabilities | 8,050 | 7,837 | |||||||||||||||
As of December 31, 2025, the carrying value of our equity method investments was $432 million higher than our share of the underlying net assets of investees. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets, except for $174 million of excess related to goodwill and other non-depreciable assets.
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $1.255 billion, $1.215 billion and $941 million in 2025, 2024 and 2023, respectively.
15. Property, Plant and Equipment (PP&E)
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Gross PP&E | Accumulated Depreciation | Net PP&E | Gross PP&E | Accumulated Depreciation | Net PP&E | ||||||||||||||||||||||||||||||||
| Refining & Marketing | $ | 34,372 | $ | 20,462 | $ | 13,910 | $ | 32,965 | $ | 19,015 | $ | 13,950 | ||||||||||||||||||||||||||
| Midstream | 34,057 | 11,690 | 22,367 | 30,697 | 10,798 | 19,899 | ||||||||||||||||||||||||||||||||
| Renewable Diesel | 970 | 396 | 574 | 976 | 338 | 638 | ||||||||||||||||||||||||||||||||
| Corporate | 1,610 | 1,064 | 546 | 1,679 | 1,138 | 541 | ||||||||||||||||||||||||||||||||
Total(a) | $ | 71,009 | $ | 33,612 | $ | 37,397 | $ | 66,317 | $ | 31,289 | $ | 35,028 | ||||||||||||||||||||||||||
(a) Includes finance leases. See Note 26.
Property, plant and equipment includes construction in progress of $2.91 billion and $1.78 billion at December 31, 2025 and 2024, respectively, which primarily relates to capital projects at our refineries and midstream facilities.
16. Goodwill and Intangibles
Goodwill
MPC annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount. There were no impairments of goodwill required based on our annual test of goodwill in 2025 and 2024.
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.
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The changes in the carrying amount of goodwill for 2025 were as follows:
| (Millions of dollars) | Refining & Marketing | Midstream | Total | ||||||||||||||
| Balance as of December 31, 2023 | $ | 561 | $ | 7,683 | $ | 8,244 | |||||||||||
| Impairment losses | — | — | — | ||||||||||||||
| Balance as of December 31, 2024 | 561 | 7,683 | 8,244 | ||||||||||||||
| Acquisitions | — | 1,110 | 1,110 | ||||||||||||||
| Impairment losses | — | — | — | ||||||||||||||
| Balance as of December 31, 2025 | $ | 561 | $ | 8,793 | $ | 9,354 | |||||||||||
| Gross goodwill as of December 31, 2025 | $ | 6,141 | $ | 11,934 | $ | 18,075 | |||||||||||
| Accumulated impairment losses | (5,580) | (3,141) | (8,721) | ||||||||||||||
| Balance as of December 31, 2025 | $ | 561 | $ | 8,793 | $ | 9,354 | |||||||||||
Intangible Assets
Our definite lived intangible assets as of December 31, 2025 and 2024 are as shown below.
| December 31, 2025 | December 31, 2024 | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Gross | Accumulated Amortization | Net | Gross | Accumulated Amortization | Net | |||||||||||||||||||||||||||||
| Customer contracts and relationships | $ | 5,245 | $ | 2,623 | $ | 2,622 | $ | 4,111 | $ | 2,446 | $ | 1,665 | |||||||||||||||||||||||
| Brand rights and tradenames | 100 | 100 | — | 101 | 89 | 12 | |||||||||||||||||||||||||||||
| Royalty agreements | 142 | 126 | 16 | 141 | 120 | 21 | |||||||||||||||||||||||||||||
| Other | 38 | 33 | 5 | 36 | 31 | 5 | |||||||||||||||||||||||||||||
| Total | $ | 5,525 | $ | 2,882 | $ | 2,643 | $ | 4,389 | $ | 2,686 | $ | 1,703 | |||||||||||||||||||||||
At both December 31, 2025 and 2024, we had indefinite lived intangible assets of $71 million, which are emission allowance credits.
Amortization expense was $271 million in 2025 and $266 million in 2024. Estimated future amortization expense for the next five years related to the intangible assets at December 31, 2025 is as follows:
| (Millions of dollars) | |||||
| 2026 | $ | 283 | |||
| 2027 | 254 | ||||
| 2028 | 238 | ||||
| 2029 | 91 | ||||
| 2030 | 91 | ||||
17. Fair Value Measurements
Fair Values – Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2025 and 2024 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables.
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| December 31, 2025 | |||||||||||||||||||||||||||||||||||
| Fair Value Hierarchy | |||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Level 1 | Level 2 | Level 3 | Netting and Collateral(a) | Net Carrying Value on Balance Sheet(b) | Collateral Pledged Not Offset | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 243 | $ | — | $ | — | $ | (226) | $ | 17 | $ | 10 | |||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 236 | $ | — | $ | — | $ | (236) | $ | — | $ | — | |||||||||||||||||||||||
| Embedded derivatives in commodity contracts | — | — | 41 | — | 41 | — | |||||||||||||||||||||||||||||
| Contingent consideration, liability | — | — | 236 | — | 236 | — | |||||||||||||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||||||||||||||
| Fair Value Hierarchy | |||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Level 1 | Level 2 | Level 3 | Netting and Collateral(a) | Net Carrying Value on Balance Sheet(b) | Collateral Pledged Not Offset | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 139 | $ | — | $ | — | $ | (132) | $ | 7 | $ | 16 | |||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 144 | $ | — | $ | — | $ | (144) | $ | — | $ | — | |||||||||||||||||||||||
| Embedded derivatives in commodity contracts | — | — | 58 | — | 58 | — | |||||||||||||||||||||||||||||
(a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2025, cash collateral of $10 million was netted with mark-to-market derivative liabilities. As of December 31, 2024, cash collateral of $12 million was netted with mark-to-market derivative liabilities.
(b) We have no derivative contracts which are subject to master netting arrangements reflected gross on the balance sheet.
Level 3 instruments include a liability for contingent consideration related to the BANGL Acquisition earnout provision and an embedded derivative liability for a natural gas purchase commitment embedded in a keep-whole processing agreement.
The fair value calculation for the contingent consideration liability was estimated using discounted cash flows based on a Monte Carlo simulation. Future earnout payments are tied to the achievement of EBITDA growth from 2026 to 2029, which includes significant unobservable input of forecasted throughput volumes. The earnout payment will continue to be remeasured at fair value each quarter with changes in fair value recognized in earnings until either the EBITDA targets are met or the earnout period ends, with the total payout capped at $275 million.
The fair value calculation for the embedded derivative liability at December 31, 2025 used significant unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging from $0.60 to $1.19 per gallon with a weighted average of $0.72 per gallon and (2) a 100 percent probability of renewable for the five-year term of the natural gas purchase commitment and related keep-whole processing agreement. Increases or decreases in the fractionation spread result in an increase or decrease in the fair value of the embedded derivative liability.
The following is a reconciliation of the beginning and ending balances recorded for net liabilities classified as Level 3 in the fair value hierarchy.
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Beginning balance | $ | 58 | $ | 61 | |||||||
Contingent consideration(a) | 234 | — | |||||||||
Unrealized and realized (gain) loss included in net income(b) | (5) | 10 | |||||||||
| Settlements of derivative instruments | (10) | (13) | |||||||||
| Ending balance | $ | 277 | $ | 58 | |||||||
The amount of total (gain) loss for the period included in earnings attributable to the change in unrealized loss relating to liabilities still held at the end of period(b): | $ | (7) | $ | 7 | |||||||
(a) Liability recorded in the third quarter of 2025 related to the BANGL Acquisition earnout provision.
(b) The gain/loss is included in cost of revenues on the consolidated statements of income.
See Note 18 for the income statement impacts of our derivative instruments.
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Fair Values – Reported
We believe the carrying value of our other financial instruments, including cash and cash equivalents, receivables, accounts payable and certain accrued liabilities, approximate fair value. Our fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, historical incurrence of credit losses and expected insignificance of future credit losses, which includes an evaluation of counterparty credit risk. The borrowings under our revolving credit facilities, which include variable interest rates, approximate fair value. The fair value of our long-term debt is estimated based on average bid prices obtained from broker quotes and is categorized in level 3 of the fair value hierarchy. The carrying and fair values of our debt were approximately $32.4 billion and $31.1 billion at December 31, 2025, respectively, and approximately $26.9 billion and $25.0 billion at December 31, 2024, respectively. These carrying and fair values of our debt exclude the unamortized issuance costs, which are netted against our total debt.
18. Derivatives
For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 17. See Note 2 for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.
The following table presents the fair value of derivative instruments as of December 31, 2025 and 2024 and the line items in the consolidated balance sheets in which the fair values are reflected. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements including cash collateral on deposit with, or received from, brokers. We offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of offset exists. As a result, the asset and liability amounts below will not agree with the amounts presented in our consolidated balance sheets.
| (Millions of dollars) | December 31, 2025 | December 31, 2024 | |||||||||||||||||||||
| Balance Sheet Location | Asset | Liability | Asset | Liability | |||||||||||||||||||
| Commodity derivatives | |||||||||||||||||||||||
| Other current assets | $ | 243 | $ | 236 | $ | 139 | $ | 144 | |||||||||||||||
Other current liabilities(a) | — | 6 | — | 10 | |||||||||||||||||||
Deferred credits and other liabilities(a) | — | 35 | — | 48 | |||||||||||||||||||
(a) Includes embedded derivatives.
The table below summarizes open commodity derivative contracts for crude oil, refined products, blending products and soybean oil as of December 31, 2025.
| Percentage of contracts that expire next quarter | Position | ||||||||||||||||
| (Units in thousands of barrels) | Long | Short | |||||||||||||||
Exchange-traded(a) | |||||||||||||||||
| Crude oil | 56.1% | 40,038 | 41,459 | ||||||||||||||
| Refined products | 80.8% | 37,457 | 39,082 | ||||||||||||||
| Blending products | 91.6% | 7,225 | 6,502 | ||||||||||||||
| Soybean oil | 94.9% | 1,171 | 1,422 | ||||||||||||||
(a) Included in exchange-traded are spread contracts in thousands of barrels: Crude oil - 3,600 long and 2,970 short; Refined products - 3,156 long and 3,041 short; Blending products - 173 long. There are no spread contracts for Soybean oil.
The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income:
| (Millions of dollars) | Gain (Loss) | ||||||||||||||||
| Income Statement Location | 2025 | 2024 | 2023 | ||||||||||||||
| Sales and other operating revenues | $ | — | $ | 1 | $ | 7 | |||||||||||
| Cost of revenues | (25) | (94) | (15) | ||||||||||||||
| Other income | 1 | 2 | 2 | ||||||||||||||
| Total | $ | (24) | $ | (91) | $ | (6) | |||||||||||
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19. Debt
Our outstanding borrowings at December 31, 2025 and 2024 consisted of the following:
| (Millions of dollars) | December 31, 2025 | December 31, 2024 | |||||||||
| Marathon Petroleum Corporation: | |||||||||||
| Senior notes | $ | 6,449 | $ | 5,699 | |||||||
| MARAD debt | 161 | 174 | |||||||||
| Finance lease obligations | 689 | 718 | |||||||||
| Total | 7,299 | 6,591 | |||||||||
| MPLX LP: | |||||||||||
| Senior notes | 26,000 | 21,200 | |||||||||
| Finance lease obligations | 6 | 6 | |||||||||
| Total | 26,006 | 21,206 | |||||||||
| Total debt | 33,305 | 27,797 | |||||||||
| Unamortized debt issuance costs | (204) | (142) | |||||||||
| Unamortized discount, net of unamortized premium | (225) | (174) | |||||||||
| Amounts due within one year | (2,371) | (3,049) | |||||||||
| Total long-term debt due after one year | $ | 30,505 | $ | 24,432 | |||||||
Commercial Paper
We have in place 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 the MPC Credit Agreement.
MPC Senior Notes
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Senior notes, 4.700% due May 2025 | $ | — | $ | 1,250 | |||||||
| Senior notes, 5.125% due December 2026 | 719 | 719 | |||||||||
| Senior notes, 3.800% due April 2028 | 496 | 496 | |||||||||
| Senior notes, 5.150% due March 2030 | 1,100 | — | |||||||||
| Senior notes, 5.700% due March 2035 | 900 | — | |||||||||
| Senior notes, 6.500% due March 2041 | 1,250 | 1,250 | |||||||||
| Senior notes, 4.750% due September 2044 | 800 | 800 | |||||||||
| Senior notes, 5.850% due December 2045 | 250 | 250 | |||||||||
| Senior notes, 4.500% due April 2048 | 498 | 498 | |||||||||
| Andeavor senior notes, 3.800% - 5.125% due 2026 – 2048 | 36 | 36 | |||||||||
| Senior notes, 5.000%, due September 2054 | 400 | 400 | |||||||||
| Total | $ | 6,449 | $ | 5,699 | |||||||
2025 Activity
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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2024 Activity
On September 16, 2024, we repaid the $750 million outstanding principal amount of 3.625 percent senior notes due September 2024 at maturity using cash on hand.
Interest on each series of senior notes is payable semi-annually in arrears. The MPC senior notes are unsecured and unsubordinated obligations of MPC and rank equally with all of MPC’s other existing and future unsecured and unsubordinated indebtedness. The MPC senior notes are non-recourse to our subsidiaries and structurally subordinated to the indebtedness of our subsidiaries, including the outstanding indebtedness of Andeavor and MPLX. The Andeavor senior notes are unsecured, unsubordinated obligations of Andeavor and are non-recourse to MPC and any of MPC’s subsidiaries other than Andeavor.
MARAD Debt
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Bonds, 3.432% due August 2036 | $ | 51 | $ | 55 | |||||||
| Bonds, 3.477% due January 2037 | 53 | 57 | |||||||||
| Bonds, 3.609% due January 2038 | 57 | 62 | |||||||||
| Total | $ | 161 | $ | 174 | |||||||
During the fourth quarter of 2024, MPC purchased the remaining 50 percent interest in Coastal Holdings from our joint venture partner and assumed $174 million in aggregate principal amount of MARAD Debt obligations issued by Blue Water Holdings, a subsidiary of Coastal Holdings LLC, which owns three 750 series ATB Vessels. Blue Water Holdings remains the primary obligor under the MARAD Debt. The U.S. Department of Transportation Maritime Administration (“MARAD”) has guaranteed certain of Blue Water Holdings’ obligations under the MARAD Debt and Blue Water Holdings has agreed to reimburse MARAD for any payments it makes with respect to the MARAD Debt pursuant to the guaranty. Blue Water Holdings’ reimbursement obligations to MARAD with respect to the MARAD Debt are secured by a mortgage on the three ATB Vessels and certain related rights and assets and are guaranteed by Marathon Petroleum Corporation.
The agreements that govern the MARAD Debt, including the indenture, security agreement and guarantee contain customary representations and warranties as well as affirmative and negative covenants, events of defaults and other provisions, we believe are typical for U.S. government guaranteed obligations of this type. As of December 31, 2025, we were in compliance with the covenants contained in the MARAD Debt documents.
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MPLX Senior Notes
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Senior notes, 4.000% due February 2025 | $ | — | $ | 500 | |||||||
| Senior notes, 4.875% due June 2025 | — | 1,189 | |||||||||
| MarkWest senior notes, 4.875% due 2025 | — | 11 | |||||||||
| Senior notes, 1.750% due March 2026 | 1,500 | 1,500 | |||||||||
| Senior notes, 4.125% due March 2027 | 1,250 | 1,250 | |||||||||
| Senior notes, 4.250% due December 2027 | 732 | 732 | |||||||||
| Senior notes, 4.000% due March 2028 | 1,250 | 1,250 | |||||||||
| Senior notes, 4.800% due February 2029 | 750 | 750 | |||||||||
| Senior notes, 2.650% due August 2030 | 1,500 | 1,500 | |||||||||
| Senior notes, 4.800% due February 2031 | 1,250 | — | |||||||||
| Senior notes, 4.950% due September 2032 | 1,000 | 1,000 | |||||||||
| Senior notes, 5.000% due January 2033 | 750 | — | |||||||||
| Senior notes, 5.000% due March 2033 | 1,100 | 1,100 | |||||||||
| Senior notes, 5.500% due June 2034 | 1,650 | 1,650 | |||||||||
| Senior notes, 5.400% due April 2035 | 1,000 | — | |||||||||
| Senior notes, 5.400% due September 2035 | 1,500 | — | |||||||||
| Senior notes, 4.500% due April 2038 | 1,750 | 1,750 | |||||||||
| Senior notes, 5.200% due March 2047 | 1,000 | 1,000 | |||||||||
| Senior notes, 5.200% due December 2047 | 487 | 487 | |||||||||
| ANDX senior notes, 4.250% - 5.200% due 2027 – 2047 | 31 | 31 | |||||||||
| Senior notes, 4.700% due April 2048 | 1,500 | 1,500 | |||||||||
| Senior notes, 5.500% due February 2049 | 1,500 | 1,500 | |||||||||
| Senior notes, 4.950% due March 2052 | 1,500 | 1,500 | |||||||||
| Senior notes, 5.650% due March 2053 | 500 | 500 | |||||||||
| Senior notes, 5.950% due April 2055 | 1,000 | — | |||||||||
| Senior notes, 6.200% due September 2055 | 1,000 | — | |||||||||
| Senior notes, 4.900% due April 2058 | 500 | 500 | |||||||||
| Total | $ | 26,000 | $ | 21,200 | |||||||
2025 Activity
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.
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.
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MPLX used a portion of the net proceeds from the August 2025 MPLX Senior Notes Offering to fund the Northwind Midstream Acquisition, 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.
2024 Activity
On May 20, 2024, MPLX issued $1.65 billion aggregate principal amount of 5.50 percent senior notes due June 2034 (the “2034 Senior Notes”) in an underwritten public offering. On December 1, 2024, MPLX used $1,150 million of the net proceeds from the issuance of the 2034 Senior Notes to repay all of (i) MPLX's outstanding $1,149 million aggregate principal amount of 4.875 percent senior notes due December 2024 and (ii) MarkWest's outstanding $1 million aggregate principal amount of 4.875 percent senior notes due December 2024.
Interest on each series of MPLX fixed rate senior notes is payable semi-annually in arrears. The MPLX senior notes are unsecured, unsubordinated obligations of MPLX and are non-recourse to MPC and its subsidiaries other than MPLX and MPLX GP LLC, as the general partner of MPLX. The MPLX senior notes are non-recourse to MPLX’s subsidiaries and structurally subordinated to the indebtedness of MPLX’s subsidiaries.
Schedule of Maturities
Principal maturities of long-term debt, excluding finance lease obligations, as of December 31, 2025 for the next five years are as follows:
| (Millions of dollars) | |||||
| 2026 | $ | 2,263 | |||
| 2027 | 2,014 | ||||
| 2028 | 1,764 | ||||
| 2029 | 764 | ||||
| 2030 | 2,614 | ||||
Available Capacity under our Facilities as of December 31, 2025
| (Millions of dollars) | Total Capacity | Outstanding Borrowings | Outstanding Letters of Credit | Available Capacity | Weighted Average Interest Rate | Expiration | |||||||||||||||||||||||||||||
| MPC, excluding MPLX | |||||||||||||||||||||||||||||||||||
| MPC bank revolving credit facility | $ | 5,000 | $ | — | $ | 1 | $ | 4,999 | — | July 2027 | |||||||||||||||||||||||||
MPC trade receivables securitization facility(a) | 100 | — | — | 100 | — | September 2027 | |||||||||||||||||||||||||||||
| MPLX | |||||||||||||||||||||||||||||||||||
| MPLX bank revolving credit facility | 2,000 | — | — | 2,000 | — | July 2027 | |||||||||||||||||||||||||||||
(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.
MPC Bank Revolving Credit Facility
MPC’s credit agreement (the “MPC Credit Agreement”) matures in July 2027 and provides for a $5.0 billion unsecured revolving credit facility and letter of credit issuing capacity under the facility of up to $2.2 billion. Letters of credit issuing capacity is included in, not in addition to, the $5.0 billion borrowing capacity.
MPC has an option under the MPC Credit Agreement to increase the aggregate commitments by up to an additional $1.0 billion, subject to, among other conditions, the consent of the lenders whose commitments would be increased. In addition, the maturity date may be extended, for up to two additional one year periods, subject to, among other conditions, the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date. The MPC Credit Agreement includes sub-facilities for swing-line loans of up to $250 million and letters of credit of up to $2.2 billion (which may be increased to up to $3.0 billion upon receipt of additional letter of credit issuing commitments).
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Borrowings under the MPC Credit Agreement bear interest, at our election, at either the Adjusted Term SOFR or the Alternate Base Rate, both as defined in the MPC Credit Agreement, plus an applicable margin. We are charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the commitments and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and the commitment fees payable under the MPC Credit Agreement fluctuate based on changes, if any, to our credit ratings.
The MPC Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain a ratio of Consolidated Net Debt to Total Capitalization, each as defined in the MPC Credit Agreement, of no greater than 0.65 to 1.00 as of the last day of each fiscal quarter. The covenants also restrict, among other things, our ability and/or the ability of certain of our subsidiaries to incur debt, create liens on assets or enter into transactions with affiliates. As of December 31, 2025, we were in compliance with the covenants contained in the MPC Credit Agreement.
Trade Receivables Securitization Facility
On September 30, 2021, we entered into a Loan and Security Agreement and related documentation with a group of lenders providing for a new trade receivables securitization facility having $100 million of committed borrowing and letter of credit issuance capacity and uncommitted borrowing and letter of credit issuance capacity that can be extended at the discretion of the lenders, provided that at no time may outstanding borrowings and letters of credit issued under the facility exceed the balance of eligible trade receivables (as calculated in accordance with the Loan and Security Agreement) that are pledged as collateral under the facility. In September 2024, the trade receivables securitization facility was amended to, among other things, extend its term until September 30, 2027.
The trade receivables facility consists of certain of our wholly owned subsidiaries (“Originators”) selling or contributing on an on-going basis all of the trade receivables generated by them (the “Pool Receivables”), together with all related security and interests in the proceeds thereof, without recourse, to another wholly owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company I LLC (“TRC”), in exchange for a combination of cash, equity and/or borrowings under a subordinated note issued by TRC to one or more of the Originators. TRC may request borrowings and extensions of credit under the Loan and Security Agreement for up to the lesser of the maximum capacity under the facility or the eligible trade receivables balance of the Pool Receivables. TRC and each of the Originators have granted a security interest in all of their rights, title and interests in and to the Pool Receivables, together with all related security and interests in the proceeds thereof, to the lenders to secure the performance of TRC’s and the Originators’ payment and other obligations under the facility. In addition, Marathon Petroleum Corporation has issued a performance guaranty in favor of the lenders guaranteeing the performance by TRC and the Originators of their obligations under the facility.
To the extent that TRC retains an ownership interest in the Pool Receivables, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the lenders to secure its obligations under the Loan and Security Agreement.
TRC pays floating-rate interest charges and usage fees on amounts outstanding under the trade receivables facility, if any, unused fees on the portion of unused commitments and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the trade receivables facility.
The Loan and Security Agreement and other documents comprising the facility contain representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to be eligible receivables that count towards the borrowing base under the trade receivables facility. In addition, the lender’s commitments to extend loans and credits under the facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain events of default that are included in the Loan and Security Agreement and other facility documentation, all of which we consider to be usual and customary for arrangements of this type. As of December 31, 2025, we were in compliance with the covenants contained in the Loan and Security Agreement and other facility documentation.
MPLX Bank Revolving Credit Facility
MPLX’s credit agreement (the “MPLX Credit Agreement”) matures in July 2027 and, among other things, provides for a $2.0 billion unsecured revolving credit facility and letter of credit issuing capacity under the facility of up to $150 million. Letters of credit issuing capacity is included in, not in addition to, the $2.0 billion borrowing capacity.
The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1.0 billion, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended, for up to two additional one year periods, subject to, among other conditions, the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date.
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Borrowings under the MPLX Credit Agreement bear interest, at MPLX’s election, at either the Adjusted Term SOFR or the Alternate Base Rate, both as defined in the MPLX Credit Agreement, plus an applicable margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the commitments and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and the commitment fees payable under the MPLX Credit Agreement fluctuate based on changes, if any, to MPLX’s credit ratings.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA, both as defined in the MPLX Credit Agreement, for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. The covenants also restrict, among other things, MPLX’s ability and/or the ability of certain of its subsidiaries to incur debt, create liens on assets and enter into transactions with affiliates. As of December 31, 2025, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
20. Revenue
The following table presents our revenues from external customers disaggregated by segment and product line:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Refining & Marketing | |||||||||||||||||
| Refined products | $ | 116,504 | $ | 122,429 | $ | 132,675 | |||||||||||
| Crude oil | 5,817 | 7,298 | 7,423 | ||||||||||||||
| Services and other | 1,931 | 1,861 | 1,737 | ||||||||||||||
| Total revenues from external customers | 124,252 | 131,588 | 141,835 | ||||||||||||||
| Midstream | |||||||||||||||||
| Refined products | 2,022 | 1,668 | 1,675 | ||||||||||||||
Services and other(a) | 3,606 | 3,529 | 3,236 | ||||||||||||||
| Total revenues from external customers | 5,628 | 5,197 | 4,911 | ||||||||||||||
| Renewable Diesel | |||||||||||||||||
| Refined products | 2,799 | 2,073 | 1,628 | ||||||||||||||
| Services and other | 15 | 6 | 5 | ||||||||||||||
| Total revenues from external customers | 2,814 | 2,079 | 1,633 | ||||||||||||||
| Other service revenue | 5 | — | — | ||||||||||||||
| Sales and other operating revenues | $ | 132,699 | $ | 138,864 | $ | 148,379 | |||||||||||
(a) Includes sales-type lease revenue. See Note 26.
We do not disclose information on the future performance obligations for any contract with expected duration of one year or less at inception. As of December 31, 2025, we do not have future performance obligations that are material to future periods.
Contract Balances
Our receivables primarily consist of customer receivables. Significant, non-customer balances included in our receivables at December 31, 2025 and December 31, 2024 include matching buy/sell receivables of $4.1 billion and $4.3 billion, respectively.
Our contract liabilities primarily represent advances from our customers prior to product of service delivery. At December 31, 2025 and December 31, 2024, contract liabilities were $215 million and $515 million, respectively. Contract liabilities are included in other current liabilities and deferred credits and other liabilities on our consolidated balance sheets. We classify contract liabilities as current or long-term based on the timing of when we expect to recognize revenue.
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21. Supplemental Cash Flow Information
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Net cash provided by operating activities included: | |||||||||||||||||
| Interest paid (net of amounts capitalized) | $ | 1,219 | $ | 1,247 | $ | 1,200 | |||||||||||
| Income taxes paid to taxing authorities | |||||||||||||||||
Federal(a) | 333 | 635 | 2,321 | ||||||||||||||
| State and local: | |||||||||||||||||
| California | 22 | 45 | 98 | ||||||||||||||
| Other | 33 | 46 | 327 | ||||||||||||||
| Foreign | 18 | 6 | 5 | ||||||||||||||
| Total | 406 | 732 | 2,751 | ||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities | |||||||||||||||||
| Payments on operating leases | 530 | 532 | 493 | ||||||||||||||
| Interest payments under finance lease obligations | 33 | 25 | 25 | ||||||||||||||
| Net cash provided by financing activities included: | |||||||||||||||||
| Principal payments under finance lease obligations | 108 | 82 | 79 | ||||||||||||||
| Non-cash investing and financing activities: | |||||||||||||||||
| Right of use assets obtained in exchange for new operating lease obligations | 724 | 637 | 465 | ||||||||||||||
| Right of use assets obtained in exchange for new finance lease obligations | 85 | 302 | 21 | ||||||||||||||
Contribution of assets(b) | 115 | — | — | ||||||||||||||
Book value of equity method investment(c) | 282 | 50 | 311 | ||||||||||||||
Contingent consideration(d) | 234 | — | — | ||||||||||||||
(a) Includes $332 million and $565 million in 2025 and 2024, respectively, paid to third parties and related parties for transferable tax credits. The 2025 total includes $221 million paid to Martinez Renewables LLC.
(b) Represents the book value of assets contributed by MPLX to a JV.
(c) 2025 and 2023 represents the book value of MPLX’s equity method investment in BANGL and Torñado, respectively, prior to MPLX buying out the remaining interest in these entities. 2024 represents the book value of Coastal Holdings prior to MPC buying out the remaining 50 percent interest from our joint venture partner. See Note 5 for additional information.
(d) See Note 5 - BANGL, LLC Acquisitions
The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Additions to property, plant and equipment per the consolidated statements of cash flows | $ | 3,486 | $ | 2,533 | $ | 1,890 | |||||||||||
| Increase in capital accruals | 143 | 34 | 184 | ||||||||||||||
| Total capital expenditures | $ | 3,629 | $ | 2,567 | $ | 2,074 | |||||||||||
22. Other Current Liabilities
The following summarizes the components of other current liabilities:
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Environmental credits liability | $ | 463 | $ | 422 | |||||||
| Accrued interest payable | 449 | 314 | |||||||||
| Other current liabilities | 341 | 419 | |||||||||
| Total other current liabilities | $ | 1,253 | $ | 1,155 | |||||||
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23. Accumulated Other Comprehensive Income (Loss)
The following table shows the changes in accumulated other comprehensive income (loss) by component. Amounts in parentheses indicate debits.
| (Millions of dollars) | Pension Benefits | Other Benefits | Other | Total | |||||||||||||||||||
| Balance as of December 31, 2022 | $ | (163) | $ | 165 | $ | — | $ | 2 | |||||||||||||||
Other comprehensive income (loss) before reclassifications, net of tax of $(22) | (60) | (21) | 2 | (79) | |||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive loss: | |||||||||||||||||||||||
Amortization of prior service credit(a) | (45) | (22) | — | (67) | |||||||||||||||||||
Amortization of actuarial gain(a) | (5) | — | — | (5) | |||||||||||||||||||
Settlement gain(a) | (1) | — | — | (1) | |||||||||||||||||||
| Other | — | — | (1) | (1) | |||||||||||||||||||
| Tax effect | 13 | 7 | — | 20 | |||||||||||||||||||
| Other comprehensive income (loss) | (98) | (36) | 1 | (133) | |||||||||||||||||||
| Balance as of December 31, 2023 | (261) | 129 | 1 | (131) | |||||||||||||||||||
Other comprehensive income (loss) before reclassifications, net of tax of $16 | 44 | 10 | (2) | 52 | |||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive loss: | |||||||||||||||||||||||
Amortization of prior service credit(a) | (33) | (22) | — | (55) | |||||||||||||||||||
Amortization of actuarial loss(a) | 6 | — | — | 6 | |||||||||||||||||||
Settlement loss(a) | 3 | — | — | 3 | |||||||||||||||||||
| Tax effect | 6 | 5 | — | 11 | |||||||||||||||||||
| Other comprehensive income (loss) | 26 | (7) | (2) | 17 | |||||||||||||||||||
| Balance as of December 31, 2024 | (235) | 122 | (1) | (114) | |||||||||||||||||||
Other comprehensive income (loss) before reclassifications, net of tax of $5 | 19 | (1) | (1) | 17 | |||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive loss: | |||||||||||||||||||||||
Amortization of prior service credit(a) | (9) | (22) | — | (31) | |||||||||||||||||||
Amortization of actuarial loss(a) | 17 | — | — | 17 | |||||||||||||||||||
Settlement loss(a) | 2 | — | — | 2 | |||||||||||||||||||
| Other | — | — | 1 | 1 | |||||||||||||||||||
| Tax effect | (3) | 6 | — | 3 | |||||||||||||||||||
| Other comprehensive income (loss) | 26 | (17) | — | 9 | |||||||||||||||||||
| Balance as of December 31, 2025 | $ | (209) | $ | 105 | $ | (1) | $ | (105) | |||||||||||||||
(a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 24.
24. Pension and Other Postretirement Benefits
We have two noncontributory defined benefit pension plans. One plan is frozen and covered certain employees of our former Speedway LLC subsidiary. The other plan is active and covers substantially all of our employees. Benefits under these plans are based on a now frozen final average pay type of benefit based on age, years of service and final average pensionable earnings, and a cash balance type of benefit. The years of service component for the final average pay type of benefit was frozen as of December 31, 2009, and certain of the pensionable earnings components were frozen as of December 31, 2012. Benefits for the cash balance type of benefit began on January 1, 2010 for our continuing active plan, and began on January 1, 2016 for our frozen plan, and are based on a cash balance formula with an annual percentage of eligible pay credited based upon age and years of service or at a flat rate of eligible pay, depending on covered employee group. Substantially all of our employees also accrue benefits under a defined contribution plan.
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Cash balance weighted average interest crediting rates | 4.19 | % | 4.56 | % | 3.57 | % | |||||||||||
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We also have other postretirement benefits covering most employees. Retiree health care benefits are provided through comprehensive hospital, surgical, major medical benefit, prescription drug and related health benefit provisions subject to various cost sharing features. Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not funded in advance.
In connection with the Andeavor acquisition, we assumed a number of additional qualified and nonqualified noncontributory benefit pension plans, covering substantially all former Andeavor employees. Benefits under these plans are determined based on final average compensation and years of service through December 31, 2010 and a cash balance formula for service beginning January 1, 2011. These plans were frozen as of December 31, 2018. Further, as of December 31, 2019, the qualified plans were merged with our existing qualified plans in which the actuarial assumptions were materially the same between the plans. We also assumed a number of additional postretirement benefits covering eligible employees. These benefits were merged with our existing benefits beginning January 1, 2019.
Obligations and Funded Status
The accumulated benefit obligation for all defined benefit pension plans was $2,818 million and $2,579 million as of December 31, 2025 and 2024.
The following summarizes the projected benefit obligations and funded status for our defined benefit pension and other postretirement plans:
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Benefit obligations at January 1 | $ | 2,685 | $ | 2,563 | $ | 669 | $ | 679 | |||||||||||||||
| Service cost | 220 | 219 | 20 | 21 | |||||||||||||||||||
| Interest cost | 144 | 122 | 35 | 32 | |||||||||||||||||||
| Actuarial (gain) loss | 109 | (32) | 4 | (14) | |||||||||||||||||||
| Benefits paid | (226) | (187) | (50) | (49) | |||||||||||||||||||
| Benefit obligations at December 31 | 2,932 | 2,685 | 678 | 669 | |||||||||||||||||||
| Fair value of plan assets at January 1 | 2,158 | 2,082 | — | — | |||||||||||||||||||
| Actual return on plan assets | 267 | 161 | — | — | |||||||||||||||||||
| Employer contributions | 200 | 102 | 50 | 49 | |||||||||||||||||||
| Benefits paid from plan assets | (226) | (187) | (50) | (49) | |||||||||||||||||||
| Fair value of plan assets at December 31 | 2,399 | 2,158 | — | — | |||||||||||||||||||
| Funded status at December 31 | $ | (533) | $ | (527) | $ | (678) | $ | (669) | |||||||||||||||
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31 include:
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Noncurrent assets | $ | 23 | $ | 22 | $ | — | $ | — | |||||||||||||||
| Current liabilities | (10) | (11) | (51) | (50) | |||||||||||||||||||
| Noncurrent liabilities | (546) | (538) | (627) | (619) | |||||||||||||||||||
| Accrued benefit cost | $ | (533) | $ | (527) | $ | (678) | $ | (669) | |||||||||||||||
Included in accumulated other comprehensive loss at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Net actuarial loss | $ | 367 | $ | 404 | $ | 40 | $ | 36 | |||||||||||||||
| Prior service credit | (27) | (36) | (159) | (181) | |||||||||||||||||||
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Amounts exclude those related to LOOP and Explorer, equity method investees with defined benefit pension and postretirement plans for which net losses (gains) of less than $1 million and $7 million were recorded in accumulated other comprehensive income (loss) in 2025, reflecting our ownership share.
Components of Net Periodic Benefit Cost and Other Comprehensive (Income) Loss
The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive loss (pretax) for our defined benefit pension and other postretirement plans.
| Pension Benefits | Other Benefits | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||
| Service cost | $ | 224 | $ | 227 | $ | 201 | $ | 20 | $ | 21 | $ | 18 | |||||||||||||||||||||||
| Interest cost | 144 | 122 | 116 | 35 | 32 | 31 | |||||||||||||||||||||||||||||
| Expected return on plan assets | (144) | (146) | (163) | — | — | — | |||||||||||||||||||||||||||||
| Amortization of prior service credit | (9) | (33) | (45) | (22) | (22) | (22) | |||||||||||||||||||||||||||||
| Amortization of actuarial (gain) loss | 17 | 6 | (5) | — | — | — | |||||||||||||||||||||||||||||
| Settlement (gain) loss | 2 | 3 | (1) | — | — | — | |||||||||||||||||||||||||||||
Net periodic benefit cost(a) | $ | 234 | $ | 179 | $ | 103 | $ | 33 | $ | 31 | $ | 27 | |||||||||||||||||||||||
| Actuarial (gain) loss | $ | (18) | $ | (54) | $ | 75 | $ | 4 | $ | (15) | $ | 31 | |||||||||||||||||||||||
| Amortization of actuarial gain (loss) | (19) | (9) | 6 | — | — | — | |||||||||||||||||||||||||||||
| Amortization of prior service credit | 9 | 33 | 45 | 22 | 22 | 22 | |||||||||||||||||||||||||||||
| Total recognized in other comprehensive (income) loss | $ | (28) | $ | (30) | $ | 126 | $ | 26 | $ | 7 | $ | 53 | |||||||||||||||||||||||
| Total recognized in net periodic benefit cost and other comprehensive loss | $ | 206 | $ | 149 | $ | 229 | $ | 59 | $ | 38 | $ | 80 | |||||||||||||||||||||||
(a) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
The components of net periodic benefit cost, other than the service cost component, are included in net interest and other financial costs on the consolidated statements of income.
For certain of our pension plans, lump sum payments to employees retiring in 2025, 2024 and 2023 exceeded the plan’s total service and interest costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, pension settlement expenses were recorded in 2025, 2024 and 2023.
Plan Assumptions
The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2025, 2024 and 2023.
| Pension Benefits | Other Benefits | ||||||||||||||||||||||||||||||||||
| 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||||||||||||||||||||||||||||||
| Benefit obligation: | |||||||||||||||||||||||||||||||||||
| Discount rate | 5.25 | % | 5.55 | % | 4.85 | % | 5.40 | % | 5.58 | % | 4.88 | % | |||||||||||||||||||||||
| Rate of compensation increase | 3.83 | % | 4.18 | % | 4.18 | % | 3.83 | % | 4.18 | % | 4.18 | % | |||||||||||||||||||||||
| Net periodic benefit cost: | |||||||||||||||||||||||||||||||||||
| Discount rate | 5.53 | % | 4.85 | % | 5.10 | % | 5.58 | % | 4.88 | % | 5.08 | % | |||||||||||||||||||||||
| Expected long-term return on plan assets | 7.10 | % | 6.80 | % | 7.00 | % | — | % | — | % | — | % | |||||||||||||||||||||||
| Rate of compensation increase | 3.83 | % | 4.18 | % | 4.18 | % | 3.83 | % | 4.18 | % | 4.18 | % | |||||||||||||||||||||||
Expected Long-term Return on Plan Assets
The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are
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developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.
Assumed Health Care Cost Trend
The following summarizes the assumed health care cost trend rates.
| December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Health care cost trend rate assumed for the following year: | |||||||||||||||||
| Medical: Pre-65 | 7.80 | % | 7.90 | % | 7.70 | % | |||||||||||
| Prescription drugs | 13.30 | % | 12.50 | % | 10.80 | % | |||||||||||
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate): | |||||||||||||||||
| Medical: Pre-65 | 4.50 | % | 4.50 | % | 4.50 | % | |||||||||||
| Prescription drugs | 4.50 | % | 4.50 | % | 4.50 | % | |||||||||||
| Year that the rate reaches the ultimate trend rate: | |||||||||||||||||
| Medical: Pre-65 | 2035 | 2034 | 2032 | ||||||||||||||
| Prescription drugs | 2035 | 2034 | 2032 | ||||||||||||||
Increases in the post-65 medical plan premium for the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan have been permanently eliminated.
Plan Investment Policies and Strategies
The investment policies for our pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) diversify plan investments across asset classes to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future returns.
The investment goals are implemented to manage the plans’ funded status volatility and minimize future cash contributions. The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans’ liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies. At December 31, 2025, the primary plan’s targeted asset allocation was 50 percent equity, private equity, real estate, and timber securities and 50 percent fixed income securities.
Fair Value Measurements
Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset category at December 31, 2025 and 2024.
Cash and cash equivalents
Cash and cash equivalents include a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at net asset value (“NAV”) on a scheduled basis using a cost approach and is considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers are valued using a cost approach and are considered Level 2.
Equity
Equity investments include common stock, mutual and pooled funds. Common stock investments are valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are considered Level 2.
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Fixed Income
Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal bonds. These securities are priced on observable inputs using a combination of market, income and cost approaches. These securities are considered Level 2 assets. Fixed income also includes a well-diversified bond portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a market approach and is considered Level 2.
Private Equity
Private equity investments include interests in limited partnerships which are valued using information provided by external managers for each individual investment held in the fund. These holdings are considered Level 3.
Real Estate
Real estate investments consist of interests in limited partnerships. These holdings are either appraised or valued using the investment manager’s assessment of assets held. These holdings are considered Level 3.
Other
Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest U.S. These holdings are either appraised or valued using the investment manager’s assessment of assets held. These holdings are considered Level 3. Other investments classified as Level 2 include derivative transactions.
The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2025 and 2024.
| December 31, 2025 | December 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 74 | $ | — | $ | 74 | $ | — | $ | 62 | $ | — | $ | 62 | |||||||||||||||||||||||||||||||
| Equity: | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stocks | 53 | — | — | 53 | 52 | — | — | 52 | |||||||||||||||||||||||||||||||||||||||
| Mutual funds | 141 | — | — | 141 | 125 | — | — | 125 | |||||||||||||||||||||||||||||||||||||||
| Pooled funds | — | 953 | — | 953 | — | 871 | — | 871 | |||||||||||||||||||||||||||||||||||||||
| Fixed income: | |||||||||||||||||||||||||||||||||||||||||||||||
| Corporate | — | 675 | — | 675 | — | 637 | — | 637 | |||||||||||||||||||||||||||||||||||||||
| Government | — | 166 | — | 166 | — | 267 | — | 267 | |||||||||||||||||||||||||||||||||||||||
| Pooled funds | — | 124 | — | 124 | — | 117 | — | 117 | |||||||||||||||||||||||||||||||||||||||
| Exchange traded funds | 190 | — | — | 190 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Private equity | — | — | 6 | 6 | — | — | 9 | 9 | |||||||||||||||||||||||||||||||||||||||
| Real estate | — | — | 9 | 9 | — | — | 11 | 11 | |||||||||||||||||||||||||||||||||||||||
| Other | — | 8 | — | 8 | — | 7 | — | 7 | |||||||||||||||||||||||||||||||||||||||
| Total investments, at fair value | $ | 384 | $ | 2,000 | $ | 15 | $ | 2,399 | $ | 177 | $ | 1,961 | $ | 20 | $ | 2,158 | |||||||||||||||||||||||||||||||
Cash Flows
Contributions to defined benefit plans
Our funding policy with respect to the funded pension plans is to contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined appropriate by management. In 2025, we made contributions totaling $191 million to our funded pension plans. For 2026, we estimate required funding of $263 million, but we may also make voluntary contributions to our funded pension plans at our discretion. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $10 million and $51 million, respectively, in 2026.
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Estimated future benefit payments
The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.
| (Millions of dollars) | Pension Benefits | Other Benefits | |||||||||
| 2026 | $ | 228 | $ | 51 | |||||||
| 2027 | 243 | 52 | |||||||||
| 2028 | 250 | 53 | |||||||||
| 2029 | 260 | 55 | |||||||||
| 2030 | 266 | 55 | |||||||||
| 2031 through 2035 | 1,506 | 285 | |||||||||
Contributions to defined contribution plan
We also contribute to a defined contribution plan for eligible employees. Contributions to this plan totaled $192 million, $181 million and $176 million in 2025, 2024 and 2023, respectively.
Multiemployer Pension Plan
We contribute to one multiemployer defined benefit pension plan under the terms of a collective-bargaining agreement that covers some of our union-represented employees. The risks of participating in this multiemployer plan are different from single-employer plans in the following aspects:
•Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.
•If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
•If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an amount based on the underfunded status of the plan, referred to as a withdrawal liability.
Our participation in this plan for 2025, 2024 and 2023 is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2025 and 2024 is for the plan years ending on December 31, 2024 and December 31, 2023, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of 2025, 2024 and 2023 contributions. Our portion of the contributions does not make up more than five percent of total contributions to the plan.
Pension Protection Act Zone Status | FIP/RP Status Pending/Implemented | MPC Contributions (Millions of dollars) | Surcharge Imposed | Expiration Date of Collective – Bargaining Agreement | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Pension Fund | EIN | 2025 | 2024 | 2025 | 2024 | 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Central States, Southeast and Southwest Areas Pension Plan(a) | 366044243 | Red | Red | Implemented | $ | 4 | $ | 3 | $ | 5 | No | January 31, 2031 | ||||||||||||||||||||||||||||||||||||||||||||
(a) This agreement has a minimum contribution requirement of $561 per week per employee for 2026. A total of 254 employees participated in the plan as of December 31, 2025.
Multiemployer Health and Welfare Plan
We contribute to one multiemployer health and welfare plan that covers both active employees and retirees. Through the health and welfare plan, employees receive medical, dental, vision, prescription and disability coverage. Our contributions to this plan totaled $7 million, $5 million and $7 million for 2025, 2024 and 2023, respectively.
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25. Share-Based Compensation
Description of the Incentive Plans
Our employees and non-employee directors are eligible to receive share, share-based and other types of awards under the Marathon Petroleum Corporation 2021 Incentive Compensation Plan (“MPC 2021 Plan”). The MPC 2021 Plan authorizes the Compensation and Organization Development Committee of our board of directors (“Committee”) to grant nonqualified or incentive stock options, stock appreciation rights, share and share-based awards (including restricted stock and restricted stock unit awards), cash awards and performance awards to our employees and non-employee directors. The maximum number of shares of our common stock available for awards under the MPC 2021 Plan is 20.5 million shares. The MPC 2021 Plan became effective upon shareholder approval on April 28, 2021. Prior to that date, our employees and non-employee directors were eligible to receive share, share-based and other types of awards under the Amended and Restated Marathon Petroleum Corporation 2012 Incentive Compensation Plan (“MPC 2012 Plan”), effective April 26, 2012, and prior to that date, the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC 2011 Plan”). Shares issued as a result of awards granted under these plans are funded through the issuance of new MPC common shares.
Share-Based Awards under the Plans
Stock Options
Prior to 2021, we granted stock options to certain officer and non-officer employees under the MPC 2011 Plan and the MPC 2012 Plan. Stock options represent the right to purchase shares of our common stock at an exercise price equal to the closing price of our common stock on the date of grant. Stock options generally vest over a service period of three years and expire ten years after the grant date. We expensed stock options based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures. We used the Black Scholes option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective assumptions.
Restricted Stock Units
We grant restricted stock unit awards to certain employees and to our non-employee directors. Vested restricted stock units are distributed in shares of MPC’s common stock on the dates specified in the awards. The number of restricted stock units granted pursuant to each award is determined by dividing the target value of the award by MPC’s common stock average 30-day closing price prior to the grant date. In general, restricted stock units granted to employees vest over a requisite service period of three years. Restricted stock units granted to non-employee directors prior to May 1, 2025 were considered to vest immediately at the time of the grant for accounting purposes, as they were non-forfeitable as of the grant date and distributed upon the director’s departure from the board of directors. Restricted stock units granted to non-employee directors after April 30, 2025 are fully earned at the grant date but are subject to proration if the director departs from the board of directors prior to the one-year anniversary of the grant date. These awards are considered to vest over the one-year service period for accounting purposes. For restricted stock units granted to a non-employee director after April 30, 2025, the director may elect to defer distributions until the director’s departure from the board of directors; if no deferral election is made the restricted stock units are distributed following the one-year anniversary of the grant date.
Restricted stock unit recipients do not have the right to vote any shares of stock and accrue dividend equivalents which when vested are payable on the dates specified in the awards. Accrued dividend equivalents on vested employee awards are paid in cash. Accrued dividend equivalents on vested non-employee director awards are settled in shares of MPC common stock. We expense restricted stock units based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures. The fair values of restricted stock units are equal to the market price of our common stock on the grant date.
Performance Share Units
We grant performance share unit awards to certain officer and non-officer employees. At grant, a performance share unit has a target value equal to the MPC common stock average 30-day closing price prior to the grant date. The actual payout value of a performance share unit is based on company performance (which can range from 0 percent to 200 percent) for the three-year performance period beginning January 1 of the year of grant, multiplied by, for the awards granted in 2022, MPC’s closing share price on the date the Committee certifies performance; and for the awards granted in 2023, 2024 and 2025, MPC’s average closing share price for the final thirty calendar days at the end of the performance period. For awards granted in 2022 through 2024, and for two-thirds of the value of the awards granted in 2025 Company performance for purposes of payout will be determined by the relative ranking of the total shareholder return (“TSR”) of MPC common stock over the three-year performance period compared to the TSR of a select group of peer companies, the Standard & Poor’s 500 Index, the Alerian MLP Index, as well as the median of MPC’s compensation reference group applicable for the year the award is granted. For the remaining one-third of the value of the awards granted in 2025, Company performance for purposes of payout will be determined by MPC’s relative change in free cash flow (“FCF”) per share generated during the performance period compared to the FCF of a select group of peer companies. These awards settle 100 percent in cash and are accounted for as liability awards. We expense liability-classified performance share unit awards at fair value over the requisite service period, with mark-to-market adjustments made each quarter until payout occurs. The fair value of the TSR service condition is determined using a Monte Carlo valuation
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model. The fair value of the FCF performance condition is valued using management’s current estimate of the most probable payout percentage.
Significant assumptions used in our Monte Carlo valuation models include: 1) risk free interest rate, for which we utilize the treasury rate for the time period closest to the remaining performance period of the award being valued; 2) look-back period (in years), for which we utilize the remaining performance period of the award being valued; and 3) expected volatility, for which we utilize the historical volatility of our own stock and the stock of our peer group for the look-back period previously discussed.
In general, performance share units granted to officers have a vesting service period beginning on the grant date and ending on the last day of the three-year performance period, and performance share units granted to employees outside of our senior management vest in one-third increments at the end of each calendar year of the performance period. However, certain employees are eligible to vest in some awards earlier, subject to reaching certain age and employment milestones, with payout still occurring at the end of the original performance period.
Total Share-Based Compensation Expense
The following table reflects activity related to our share-based compensation arrangements:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Share-based compensation expense | $ | 160 | $ | 137 | $ | 211 | |||||||||||
| Tax benefit recognized on share-based compensation expense | 38 | 33 | 51 | ||||||||||||||
| Cash received by MPC upon exercise of stock option awards | 24 | 25 | 62 | ||||||||||||||
| Tax benefit received for tax deductions for stock awards exercised | 6 | 28 | 49 | ||||||||||||||
Stock Option Awards
The following is a summary of our common stock option activity in 2025:
| Number of Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Terms (in years) | Aggregate Intrinsic Value (Millions of dollars) | ||||||||||||||||||||
| Outstanding at December 31, 2024 | 506,060 | $ | 57.50 | ||||||||||||||||||||
| Exercised | (381,401) | 62.50 | |||||||||||||||||||||
Outstanding at December 31, 2025(a) | 124,659 | 42.17 | 3.5 | $ | 15 | ||||||||||||||||||
(a) All options outstanding at December 31, 2025 are fully vested and exercisable.
The intrinsic value of options exercised by MPC employees during 2025, 2024 and 2023 was $35 million, $75 million and $136 million, respectively.
As of December 31, 2025, there was no unrecognized compensation cost related to stock option awards.
Restricted Stock Unit Awards
The following is a summary of restricted stock unit award activity of our common stock in 2025:
| Restricted Stock Units | |||||||||||
| Number of Units | Weighted Average Grant Date Fair Value | ||||||||||
| Unvested at December 31, 2024 | 1,033,269 | $ | 142.08 | ||||||||
| Granted | 564,679 | 159.47 | |||||||||
| Vested | (424,718) | 120.03 | |||||||||
| Forfeited | (62,801) | 152.07 | |||||||||
| Unvested at December 31, 2025 | 1,110,429 | 158.79 | |||||||||
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The following is a summary of the values related to restricted stock unit awards held by MPC employees and non-employee directors:
| Restricted Stock Units | |||||||||||
Intrinsic Value of Awards Vested During the Period (Millions of dollars) | Weighted Average Grant Date Fair Value of Awards Granted During the Period | ||||||||||
| 2025 | $ | 71 | $ | 159.47 | |||||||
| 2024 | 102 | 171.55 | |||||||||
| 2023 | 144 | 133.94 | |||||||||
As of December 31, 2025, unrecognized compensation cost related to restricted stock unit awards was $98 million, which is expected to be recognized over a weighted average period of 1.9 years.
Performance Awards
The following is a summary of performance share unit awards activity in 2025:
| Number of Performance Share Units | |||||
| Unvested at December 31, 2024 | 427,348 | ||||
| Granted | 303,688 | ||||
| Vested | (271,706) | ||||
| Forfeited | (17,499) | ||||
| Unvested at December 31, 2025 | 441,831 | ||||
We paid $122 million, $169 million and $14 million during the years ended 2025, 2024 and 2023, respectively, to settle performance awards.
As of December 31, 2025, unrecognized compensation cost related to performance awards was $19 million, which is expected to be recognized over a weighted average period of 1.3 years. As of December 31, 2025, the total liability associated with performance awards was $151 million.
MPLX Awards
Compensation expense for awards of MPLX units are not material to our consolidated financial statements for 2025.
26. Leases
Lessee
We lease a wide variety of facilities and equipment including land and building space, office and field equipment, storage facilities and transportation equipment. Our remaining lease terms range from less than one year to 93 years. Most long-term leases include renewal options ranging from one year to 40 years and, in certain leases, also include purchase options. The lease term included in the measurement of right of use assets and lease liabilities includes options to extend or terminate our leases that we are reasonably certain to exercise.
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Under ASC 842, the components of lease cost are shown below. Lease costs for operating leases are recognized on a straight-line basis and are reflected in the income statement based on the leased asset’s use. Lease costs for finance leases are reflected in depreciation and amortization and in net interest and other financial costs.
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Finance lease cost: | |||||||||||||||||
| Amortization of right of use assets | $ | 102 | $ | 80 | $ | 73 | |||||||||||
| Interest on lease liabilities | 33 | 26 | 25 | ||||||||||||||
| Operating lease cost | 541 | 534 | 489 | ||||||||||||||
| Variable lease cost | 68 | 60 | 54 | ||||||||||||||
| Short-term lease cost | 964 | 952 | 881 | ||||||||||||||
| Total lease cost | $ | 1,708 | $ | 1,652 | $ | 1,522 | |||||||||||
Supplemental consolidated balance sheet data related to leases were as follows:
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Operating leases | |||||||||||
| Assets | |||||||||||
| Right of use assets | $ | 1,493 | $ | 1,300 | |||||||
| Liabilities | |||||||||||
| Operating lease liabilities | $ | 489 | $ | 417 | |||||||
| Long-term operating lease liabilities | 993 | 860 | |||||||||
| Total operating lease liabilities | $ | 1,482 | $ | 1,277 | |||||||
| Weighted average remaining lease term (in years) | 4 | 4 | |||||||||
| Weighted average discount rate | 4.5 | % | 4.4 | % | |||||||
| Finance leases | |||||||||||
| Assets | |||||||||||
| Property, plant and equipment, gross | $ | 1,183 | $ | 1,118 | |||||||
| Less accumulated depreciation | 608 | 510 | |||||||||
| Property, plant and equipment, net | $ | 575 | $ | 608 | |||||||
| Liabilities | |||||||||||
| $ | 105 | $ | 94 | ||||||||
| 590 | 630 | ||||||||||
| $ | 695 | $ | 724 | ||||||||
| Weighted average remaining lease term (in years) | 8 | 9 | |||||||||
| Weighted average discount rate | 4.8 | % | 4.8 | % | |||||||
As of December 31, 2025, maturities of lease liabilities for operating lease obligations and finance lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:
| (Millions of dollars) | Operating | Finance | |||||||||
| 2026 | $ | 544 | $ | 135 | |||||||
| 2027 | 397 | 123 | |||||||||
| 2028 | 288 | 108 | |||||||||
| 2029 | 172 | 90 | |||||||||
| 2030 | 98 | 79 | |||||||||
| 2031 and thereafter | 128 | 312 | |||||||||
| Gross lease payments | 1,627 | 847 | |||||||||
| Less: imputed interest | 145 | 152 | |||||||||
| Total lease liabilities | $ | 1,482 | $ | 695 | |||||||
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Lessor
MPLX is considered to be the lessor under several operating lease agreements in accordance with GAAP related to certain fee-based natural gas transportation and processing agreements in the Marcellus and Southern Appalachia region. The primary terms of these agreements expire between 2026 and 2036; however, these contracts either have renewal options or will continue thereafter on a year-to-year basis until terminated by either party.
MPLX did not elect to use the practical expedient to combine lease and non-lease components for lessor arrangements. The tables below represent the portion of the contract allocated to the lease component based on relative standalone selling price. MPLX elected the practical expedient to carry forward historical classification conclusions until a modification of an existing agreement occurs. Once a modification occurs, the amended agreement is required to be assessed under ASC 842 to determine whether a reclassification of the lease is required.
Lease revenues are included in sales and other operating revenues on the consolidated statements of income. Lease revenues were as follows:
| (Millions of dollars) | 2025 | 2024 | 2023 | ||||||||||||||
| Operating leases: | |||||||||||||||||
| Rental income | $ | $ | $ | ||||||||||||||
| Sales-type leases: | |||||||||||||||||
| Interest income (Sales-type rental revenue-fixed minimum) | 113 | 114 | 114 | ||||||||||||||
| Interest income (Revenue from variable lease payments) | 38 | 22 | 22 | ||||||||||||||
| Sales-type lease revenue | $ | 151 | $ | 136 | $ | 136 | |||||||||||
The following is a schedule of minimum future rentals on the non-cancelable operating leases as of December 31, 2025:
| (Millions of dollars) | |||||
| 2026 | $ | 111 | |||
| 2027 | 86 | ||||
| 2028 | 78 | ||||
| 2029 | 77 | ||||
| 2030 | 63 | ||||
| 2031 and thereafter | 191 | ||||
| Total minimum future rentals | $ | 606 | |||
Annual minimum undiscounted lease payment receipts under our sales-type leases were as follows as of December 31, 2025:
| (Millions of dollars) | |||||
| 2026 | $ | 181 | |||
| 2027 | 163 | ||||
| 2028 | 154 | ||||
| 2029 | 146 | ||||
| 2030 | 138 | ||||
| 2031 and thereafter | 903 | ||||
| Total minimum future rentals | 1,685 | ||||
| Less: imputed interest | 691 | ||||
Lease receivables(a) | $ | 994 | |||
Current lease receivables(b) | $ | 108 | |||
Long-term lease receivables(c) | 886 | ||||
| Unguaranteed residual assets | 117 | ||||
| Total sales-type lease assets | $ | 1,111 | |||
(a) This amount does not include the unguaranteed residual assets.
(b) Presented in receivables, net on the consolidated balance sheets.
(c) Presented in other noncurrent assets on the consolidated balance sheets.
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Capital expenditures related to assets subject to sales-type lease arrangements were $137 million, $69 million and $50 million for the year ended December 31, 2025, 2024 and 2023, respectively. These amounts are reflected as additions to property, plant and equipment in the consolidated statements of cash flows.
The following schedule summarizes our investment in assets held under operating lease by major classes as of December 31, 2025 and 2024:
| December 31, | |||||||||||
| (Millions of dollars) | 2025 | 2024 | |||||||||
| Gathering and transportation | $ | 111 | $ | 86 | |||||||
| Processing and fractionation | 1,017 | 1,039 | |||||||||
| Pipelines | 6 | 18 | |||||||||
| Refining Logistics | 277 | — | |||||||||
| Terminals | 1 | 129 | |||||||||
| Land, building and other | 12 | 11 | |||||||||
| Property, plant and equipment | 1,424 | 1,283 | |||||||||
| Less accumulated depreciation | 567 | 458 | |||||||||
| Total property, plant and equipment, net | $ | 857 | $ | 825 | |||||||
27. Commitments and Contingencies
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which we have not recorded a liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings, discovery or court proceedings. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.
Environmental Matters
We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.
At December 31, 2025 and 2024, accrued liabilities for remediation totaled $ and $, respectively. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were $4 million and $6 million at December 31, 2025 and 2024, respectively.
We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Climate Change Litigation
Governmental and other entities in various states have filed climate-related lawsuits against a number of energy companies, including MPC. Although each suit is separate and unique, the lawsuits generally allege defendants made knowing misrepresentations about knowingly concealing, or failing to warn of the impacts of their petroleum products, which led to increased demand and worsened climate change. Plaintiffs are seeking unspecified damages and abatement under various tort theories, as well as breaches of consumer protection and unfair trade statutes. We are currently subject to such proceedings in federal or state courts in Delaware, Maryland and Oregon. The pending cases are: Mayor and City Counsel of Baltimore, Maryland v. BP P.L.C., et al., (Md. Cir. Ct.) (date instituted July 20, 2018); Delaware ex rel. Jennings v. BP America Inc., et al., (Del. Super. Ct.) (date instituted September 10, 2020); City of Annapolis v. BP P.L.C., et al., (Md. Cir. Ct.) (date instituted February 22, 2021); Anne Arundel County, Maryland v. BP P.L.C. et al., (Md. Cir. Ct.), (date instituted April 26, 2021); County of Multnomah v. Exxon Mobil Corp., et al., (Or. Cir. Ct.) (date instituted June 22, 2023).
Similar lawsuits may be filed in other jurisdictions. At this stage in the litigation, the ultimate outcome of these matters remains uncertain, and neither the likelihood of an unfavorable outcome nor the ultimate liability, if any, can be determined.
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Other Legal Proceedings
Tesoro High Plains Pipeline
In July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the Bureau of Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. After subsequent appeal proceedings and in compliance with a new order issued by the BIA, THPP paid approximately $4 million in assessed trespass damages and ceased use of the portion of the pipeline that crosses the property at issue. In March 2021, the BIA issued an order purporting to vacate the BIA's prior orders related to THPP’s alleged trespass and directed the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order. In April 2021, THPP filed a lawsuit in the District of North Dakota against the United States of America, the U.S. Department of the Interior and the BIA (collectively, the “U.S. Government Parties”) challenging the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. The case will proceed on the merits of THPP’s challenge to the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass.
We are also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these other lawsuits and proceedings will not, individually or collectively, have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Guarantees
We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.
Guarantees related to indebtedness of equity method investees
LOOP and LOCAP
MPC and MPLX hold interests in an offshore oil port, LOOP, and MPLX holds an interest in a crude oil pipeline system, LOCAP. Both LOOP and LOCAP have secured various project financings with throughput and deficiency agreements. Under the agreements, MPC, as a shipper, is required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements varies but tends to follow the terms of the underlying debt, which extend through 2040. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $210 million as of December 31, 2025.
Dakota Access Pipeline
MPLX holds a 9.19 percent indirect interest in a joint venture (“Dakota Access”), which owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline system”). In 2020, the U.S. District Court for the District of Columbia (the “D.D.C.”) ordered the U.S. Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The Army Corps issued the final EIS in late 2025 and recommended the continued operation of the pipeline. The Army Corps may issue a Record of Decision now that the final EIS has been issued. New litigation may be filed now that the final EIS has been issued.
MPLX has entered into a Contingent Equity Contribution Agreement whereby it, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring, such as a vacatur of the easement resulting in a shutdown of the pipeline, to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations.
If the vacatur of the easement results in a temporary shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is shut down. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the easement and/or return the pipeline into operation. If the vacatur of the easement results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the 1 percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of December 31, 2025, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $78 million.
Other guarantees
We have entered into other guarantees with maximum potential undiscounted payments totaling $186 million as of December 31, 2025, which primarily consist of a commitment to indemnify a joint venture member for our pro rata share of any payments made under a performance guarantee for construction of a pipeline by an equity method investee, a commitment to contribute cash to an equity method investee for certain catastrophic events in lieu of procuring insurance coverage, a commitment to pay a
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termination fee on a supply agreement if terminated during the initial term, a commitment to fund a share of the bonds issued by a government entity for construction of public utilities in the event that other industrial users of the facility default on their utility payments and leases of assets containing general lease indemnities and guaranteed residual values.
General guarantees associated with dispositions
Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
Contractual Commitments and Contingencies
At December 31, 2025, our contractual commitments to acquire property, plant and equipment totaled $453 million. Our contractual commitments to acquire property, plant and equipment totaled $260 million at December 31, 2024.
Certain natural gas processing and gathering arrangements require us to construct natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producer customers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure.
Asset Retirement Obligations
Our short-term asset retirement obligations were $37 million and $36 million at December 31, 2025 and 2024, respectively, and are included in other current liabilities in our consolidated balance sheets. Our long-term asset retirement obligations were $225 million and $210 million at December 31, 2025 and 2024, respectively, which are included in deferred credits and other liabilities in our consolidated balance sheets.
Marathon Oil indemnifications
The separation and distribution agreement and other agreements with Marathon Oil to effect our spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil and its successor, ConocoPhillips, is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil and its successor, ConocoPhillips, for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.
28. Subsequent Event
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.
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2025, the end of the period covered by this Annual Report on Form 10-K.
Management’s Report on Internal Control over Financial Reporting
MPC’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our chief executive officer and chief financial officer. Based on the results of this evaluation, MPC’s management concluded that its internal control over financial reporting was effective as of December 31, 2025.
In accordance with guidance issued by the Securities and Exchange Commission staff, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting for the first fiscal year in which the acquisition occurred. Consistent with this guidance, management’s assessment of the effectiveness of MPC’s internal control over financial reporting as of December 31, 2025, excluded the internal controls of Northwind Midstream, which was acquired in a business combination on August 29, 2025. The total assets and total revenues and other income of Northwind Midstream, a wholly-owned subsidiary, represented approximately 2% and less than 1% of the MPC’s consolidated total assets and total revenues and other income, respectively, as of and for the year ended December 31, 2025. MPC intends to include Northwind Midstream in future assessments of internal control over financial reporting.
The effectiveness of MPC’s internal control over financial reporting as of December 31, 2025 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
The “Report of Independent Registered Public Accounting Firm” is set forth in Item 8.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2025, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
During the quarter ended December 31, 2025, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of MPC adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408 of Regulation S-K).
Marathon Petroleum Termination Allowance Plan
Marathon Petroleum Company LP (“MPC LP”), an affiliate of the Company, sponsors and maintains the Marathon Petroleum Termination Allowance Plan (the “TAP Plan”), which is intended to provide eligible employees of MPC LP and its affiliates with certain severance (a “termination allowance”) and other benefits in connection with certain involuntary terminations of employment. On February 25, 2026, the Company’s Board of Directors approved changes to the termination allowance formula applicable to certain employees of the Company, including those employees who are the Company’s named executive officers.
All employees must meet certain requirements to be eligible for a termination allowance and other benefits under the TAP Plan. The amount of the termination allowance for an eligible employee who is a Senior Leader (as defined in the TAP Plan to include the Company’s named executive officers) is the sum of his or her: (a) annual base salary rate as in effect on the date preceding his or her termination date and (b) target award amount pursuant to the Company’s Annual Cash Bonus Program. The amount of the termination allowance for the Chief Executive Officer is two times the sum of his or her: (a) annual base salary rate as in effect on the date preceding his or her termination date and (b) target award amount pursuant to the Company’s Annual Cash Bonus Program.
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The foregoing description of the TAP Plan is qualified in its entirety by reference to the full text of the TAP Plan, a copy of which is attached as Exhibit 10.65 to this Annual Report on Form 10-K and incorporated herein by reference.
Former Officer Departure
On December 18, 2025, the Company announced that John J. Quaid would cease to serve as Executive Vice President and Chief Financial Officer of the Company, effective January 19, 2026. Following such effective date, Mr. Quaid has continued with the Company in a non-executive officer role for a period of transition that is expected to end on March 31, 2026.
In connection with his departure, Mr. Quaid is expected to receive approximately $1.68 million under the TAP Plan, revised as described above, as well as other benefits to which he is entitled under the Company’s pre-existing compensation plans and programs, as described in the Company’s Definitive Proxy Statement for the 2025 Annual Meeting of Shareholders, filed on Schedule 14A with the Securities and Exchange Commission on March 17, 2025. Mr. Quaid will also be eligible for a bonus under the Company’s 2026 Annual Cash Bonus Program, calculated using his 2026 eligible earnings through his departure date, which has the effect of prorating the award.
On February 25, 2026, the Compensation and Organization Development Committee of the Company’s Board of Directors approved the form of an amendment to Mr. Quaid’s 2024 Performance Share Unit Award Agreement (the “2024 PSU Award Agreement Amendment”) and the form of an amendment to Mr. Quaid’s 2025 Performance Share Unit Award Agreement (the “2025 PSU Award Agreement Amendment”). These amendments provide that 8,256 performance share units awarded under Mr. Quaid’s 2024 Performance Share Unit Award Agreement and 5,558 performance share units awarded under Mr. Quaid’s 2025 Performance Share Unit Award Agreement, which in each case reflects proration of Mr. Quaid’s time of service during the applicable performance period through his departure, will become non-forfeitable upon his departure.
The foregoing description of the 2024 PSU Award Agreement Amendment and the 2025 PSU Award Agreement Amendment is qualified in its entirety by reference to the full text of 2024 PSU Award Agreement Amendment and the 2025 PSU Award Agreement Amendment, copies of which are attached as Exhibit 10.66 and Exhibit 10.67, respectively, to this Annual Report on Form 10-K and incorporated herein by reference.
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information concerning our executive officers is included in Part I, Item 1 of this Annual Report on Form 10-K. Information concerning our directors is incorporated by reference to “Corporate Governance—Proposal 1. Election of Directors” in our Proxy Statement for the 2026 Annual Meeting of Shareholders, to be filed with the SEC within 120 days of December 31, 2025 (the “Proxy Statement”).
Our Code of Business Conduct, which applies to all of our directors, officers and employees, defines our expectations for ethical decision-making, accountability and responsibility. Our Code of Ethics for Senior Financial Officers, which is specifically applicable to our Chief Executive Officer, Chief Financial Officer, Controller and Treasurer, and other leaders performing similar functions, affirms the principle that the honesty, integrity and sound judgment of our senior executives with responsibility for preparation and certification of our financial statements is essential to the proper functioning and success of our company. These codes are available on our website at www.marathonpetroleum.com/Investors/Corporate-Governance/. We would post on our website any amendments to, or waivers from, either of these codes requiring disclosure under applicable rules within four business days following any such amendment or waiver. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.
The other information required by this Item is incorporated by reference to “Corporate Governance—Board Function and Leadership—Board Committees” and “Other Information—Insider Trading Policies and Procedures” in our Proxy Statement.
Item 11. Executive Compensation
Information required by this Item is incorporated by reference to “Executive Compensation,” “Executive Compensation—Executive Compensation Tables” (excluding the information under the subheading “Pay Versus Performance”) and “Corporate Governance—Non-Employee Director Compensation” in our Proxy Statement.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information concerning security ownership of certain beneficial owners and management required by this Item is incorporated by reference to “Other Information—Stock Ownership Information” in our Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2025 with respect to shares of our common stock that may be issued under the MPC 2021 Plan, the MPC 2012 Plan and the MPC 2011 Plan:
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights(a) | Weighted-average exercise price of outstanding options, warrants and rights(b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)(c) | ||||||||||||||
| Equity compensation plans approved by stockholders | 1,456,316 | $ | 42.17 | 19,058,052 | |||||||||||||
| Equity compensation plan not approved by stockholders | — | — | — | ||||||||||||||
| Total | 1,456,316 | N/A | 19,058,052 | ||||||||||||||
(a) Includes the following:
1) 124,659 stock options granted pursuant to the MPC 2012 Plan and not forfeited, cancelled or expired as of December 31, 2025; and
2) 1,331,657 restricted stock units granted pursuant to the MPC 2021 Plan, the MPC 2012 Plan and the MPC 2011 Plan for shares unissued and not forfeited, cancelled or expired as of December 31, 2025.
(b) Restricted stock, restricted stock units and performance units are not taken into account in the weighted-average exercise price as such awards have no exercise price.
(c) Reflects the shares available for issuance pursuant to the MPC 2021 Plan. All granting authority under the MPC 2012 Plan was revoked following the approval of the MPC 2021 Plan by shareholders on April 28, 2021. All granting authority under the MPC 2011 Plan was revoked following the approval of the MPC 2012 Plan by shareholders on April 25, 2012. Shares that (i) relate to grants made pursuant to the MPC 2012 Plan that are forfeited, cancelled or expire unexercised or (ii) are withheld or tendered to satisfy taxes related to vestings of restricted stock units under the MPC 2012 Plan, in each case, become immediately available for issuance under the MPC 2021 Plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to “Other Information—Related Party Transactions” and “Corporate Governance—Board Composition and Director Selection—Director Independence” in our Proxy Statement.
Item 14. Principal Accountant Fees and Services
Information required by this Item is incorporated by reference to “Audit Matters—Auditor Fees and Services” in our Proxy Statement.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)
2. Financial Statement Schedules
Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.
3. Exhibits:
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| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | SEC File No. | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 10.8* | 10-K | 10.32 | 2/28/2013 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.9* | 8-K | 10.1 | 3/5/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.10* | 10-K | 10.75 | 2/28/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.11* | 10-K | 10.86 | 2/28/2019 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.12* | 10-Q | 10.4 | 11/05/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.13* | 10-K | 10.43 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.14* | 10-Q | 10.2 | 11/4/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.15* | 10-K | 10.73 | 2/26/2021 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.16* | 10-K | 10.74 | 2/26/2021 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.17* | 10-K | 10.44 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.18* | 10-K | 10.22 | 2/29/2012 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.19* | 10-Q | 10.9 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.20* | 10-Q | 10.2 | 5/9/2019 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.21* | 10-Q | 10.3 | 5/7/2020 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.22* | 10-K | 10.48 | 2/23/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.23* | 10-K | 10.49 | 2/23/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.24* | 10-K | 10.52 | 2/23/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.25* | 10-K | 10.41 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.26* | 10-Q | 10.3 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.27* | 10-Q | 10.6 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.28* | 10-K | 10.42 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.29* | 10-Q | 10.7 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.30* | 10-Q | 10.4 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.31* | 10-Q | 10.1 | 4/30/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
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| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | SEC File No. | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 10.32* | 10-Q | 10.8 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.33* | 10-Q | 10.5 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.34* | 10-K | 10.50 | 2/23/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.35* | 10-Q | 10.3 | 5/2/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.36* | 10-Q | 10.1 | 8/1/2023 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.37* | 10-K | 10.36 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.38* | 10-K | 10.37 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.39* | 10-Q | 10.2 | 4/30/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.40* | 10-Q | 10.5 | 11/05/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.41* | 10-K | 10.50 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.42* | 10-Q | 10.1 | 8/5/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.43* | 10-K | 10.45 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.44* | 10-Q | 10.1 | 8/06/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.45* | 10-K | 10.48 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.46* | 10-K | 10.49 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.47* | 10-Q | 10.1 | 11/05/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.48* | 10-K | 10.44 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.49* | 10-K | 10.45 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.50* | 10-Q | 10.2 | 5/06/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.51* | 10-Q | 10.2 | 11/05/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.52* | 10-K | 10.46 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
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| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | SEC File No. | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 10.53* | 10-K | 10.47 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.54* | 10-Q | 10.1 | 5/6/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.55* | 10-Q | 10.1 | 11/4/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.56 | 8-K | 10.1 | 7/12/2022 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.57 | 8-K | 10.2 | 7/12/2022 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 10.58* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.59* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.60* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.61* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.62* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.63* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.64* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.65* | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.66* | X | |||||||||||||||||||||||||||||||||||||||||||
135
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | SEC File No. | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 10.67* | X | |||||||||||||||||||||||||||||||||||||||||||
| 19.1 | 10-K | 19.1 | 2/27/2025 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 21.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 23.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 24.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 97.1 | 10-K | 97.1 | 2/28/2024 | 001-35054 | ||||||||||||||||||||||||||||||||||||||||
| 101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded with the Inline XBRL document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||||||||||||||||||||||||||||||||||||||||||
* Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.
136
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Date: February 26, 2026 | MARATHON PETROLEUM CORPORATION | |||||||
| By: | /s/ Erin M. Brzezinski | |||||||
Erin M. Brzezinski Vice President and Controller | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 26, 2026 on behalf of the registrant and in the capacities indicated.
| Signature | Title | |||||||
| /s/ Maryann T. Mannen | Chairman of the Board, President and Chief Executive Officer (principal executive officer) | |||||||
| Maryann T. Mannen | ||||||||
| /s/ Maria A. Khoury | Executive Vice President and Chief Financial Officer (principal financial officer) | |||||||
| Maria A. Khoury | ||||||||
| /s/ Erin M. Brzezinski | Vice President and Controller (principal accounting officer) | |||||||
| Erin M. Brzezinski | ||||||||
| * | Director | |||||||
| Abdulaziz F. Alkhayyal | ||||||||
| * | Director | |||||||
| Evan Bayh | ||||||||
| * | Director | |||||||
| Jeffrey C. Campbell | ||||||||
| * | Director | |||||||
| Jonathan Z. Cohen | ||||||||
| * | Director | |||||||
| Kimberly N. Ellison-Taylor | ||||||||
| * | Director | |||||||
| Eileen P. Paterson | ||||||||
| * | Director | |||||||
| Kim K.W. Rucker | ||||||||
137
| Signature | Title | |||||||
| * | Director | |||||||
| Frank M. Semple | ||||||||
| * | Director | |||||||
| J. Michael Stice | ||||||||
| * | Director | |||||||
| John P. Surma | ||||||||
* The undersigned, by signing her name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the registrant, which is being filed herewith on behalf of such directors and officers.
| By: | /s/ Maryann T. Mannen | February 26, 2026 | ||||||||||||
Maryann T. Mannen Attorney-in-Fact | ||||||||||||||
138
