Marathon Petroleum Corp: Form 10-K for the period ended Dec 31, 2023

OVERVIEW

MPC has more than 135 years of history in the energy business, and is a leading, integrated, downstream 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. In addition, 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.

Our operations consist of two reportable operating segments: Refining & Marketing and Midstream. 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, including renewable 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, including renewable diesel, 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, 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, 2023, we owned the general partner of MPLX and approximately 65 percent of the outstanding MPLX common units.

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 2,950 mbpcd. During 2023, our refineries processed 2,677 mbpd of crude oil and 237 mbpd of other charge and blendstocks. During 2022, our refineries processed 2,761 mbpd of crude oil and 190 mbpd of other charge and blendstocks.

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.

Following is a description of each of our refineries and their capacity by region.

Gulf Coast Region (1,228 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 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 2023 was used at the refinery, with the remaining electricity being sold into the electricity grid.

Garyville, Louisiana Refinery (597 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 (1,170 mbpcd)

Catlettsburg, Kentucky Refinery (300 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 (140 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, asphalt, propane 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.

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 (71 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, heavy fuel oil, propane and NGLs and petrochemicals.

Salt Lake City, Utah Refinery (68 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, propane and NGLs and petrochemicals.

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, propane, asphalt and NGLs and petrochemicals.

Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery.

Refined Product Yields

The following table sets forth our refinery production by product group for each of the last three years.

(a) Product yields include renewable production and ethanol blending.

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.

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.

Renewable Fuels

The Martinez Renewable Fuels joint venture (the “Martinez Renewables joint venture”), included within the West Coast region, is a partnership structured as a 50/50 joint venture with Neste Corporation to convert the Martinez facility from refining petroleum to refining renewable feedstocks. The Martinez Renewables facility, which has a design capacity of 730 million gallons per year including pretreatment capabilities, began ramping up production of renewable diesel in 2023.

We hold a 49.9 percent ownership interest in ethanol production facilities in Albion, Michigan; Logansport, Indiana; Greenville, Ohio and Denison, Iowa. These plants have a combined ethanol production capacity of approximately 405 million gallons per year and are managed by our joint venture partner, The Andersons, Inc. (“The Andersons”).

The Dickinson, North Dakota, renewable fuels facility, within the Mid-Continent region, 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 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 a joint venture with Archer-Daniels-Midland Company (“ADM”) for the production of soybean oil to supply rapidly growing demand for renewable diesel fuel. The joint venture, which is named Green Bison Soy Processing, LLC (“Green Bison Soy Processing”), owns and operates a soybean processing complex in Spiritwood, North Dakota, with ADM owning 75 percent of the joint venture and MPC owning 25 percent. The Spiritwood facility sources and processes local soybeans and supplies the resulting soybean oil exclusively to MPC. The Spiritwood complex, which began operations in November 2023, is expected to produce approximately 600 million pounds of refined soybean oil annually, enough feedstock for approximately 75 million gallons of renewable diesel per year.

In 2023, we acquired 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. Current projects are under various stages of development, with the first facility reaching full commercial operation in the first half of 2023.

Our wholly owned subsidiary, Virent Inc. (“Virent”), operates an advanced biofuels facility in Madison, Wisconsin at which it is working to commercialize a process for converting biobased feedstocks into renewable fuels and chemicals. During 2023, Virent continued to advance its BioForming® technology to commercialization with demonstration activities in the aviation industry.

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, 2023, there were 7,217 brand jobber outlets in 39 states, the District of Columbia and Mexico where independent entrepreneurs primarily maintain Marathon-branded outlets. We also have long-term supply contracts for 1,114 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.

(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 such as branded retail stations were 2,385 mbpd, 2,355 mbpd and 2,338 mbpd for the years ended December 31, 2023, 2022 and 2021, respectively.

(b) Sales include renewable products.

Refined Product Sales Destined for Export

We sell gasoline, distillates and asphalt 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.

Gasoline and Distillates

We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel oils, jet fuel, kerosene, diesel and renewable diesel) to wholesale customers, branded jobbers, direct dealers and in 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, butane, xylene, benzene, cumene and toluene. 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.

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.

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 in 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 product tankers, have ownership interests in several crude oil and refined products pipeline systems and pipeline companies and have an indirect ownership interest in an ocean vessel joint venture through our investment in Crowley Coastal Partners LLC.

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.

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.

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 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 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

We believe the advancement of public policy intended to address GHG emissions, climate change, and climate adaptation will continue, with the potential for further regulations that could affect our operations. Currently, legislative and regulatory measures to address GHG emissions are in various phases of review, discussion or implementation. Reductions in GHG emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities, (iii) capture the emissions from our facilities and (iv) administer and manage any GHG emissions programs, including acquiring emission credits or allotments.

On December 2, 2023, EPA issued its final rule to regulate methane emissions from the Oil and Natural Gas Sector. The rule titled “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Gas Sector Climate Review” requires MPLX to control and reduce methane emissions within its natural gas gathering and boosting operations and gas processing facilities. 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. Concurrent with its announcement of the final methane emission rules for the oil and natural gas sector, EPA finalized updates to its social cost of carbon, methane and nitrous oxide (collectively, “social cost of greenhouse gases” or “SC-GHG”). The updated estimates are significantly higher than past estimates. A higher SC-GHG could support more stringent GHG emission regulation in various rule makings from methane emissions to vehicle tailpipe emissions.

States are becoming active in regulating GHG emissions. These measures may include state actions to develop statewide or regional programs to report emissions and impose emission reductions. These measures may also include low-carbon fuel standards, such as the California program, or a state carbon tax. These 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. For example, California has enacted a cap-and-trade program. Much of the compliance costs associated with the California program are ultimately passed on to the consumer in the form of higher fuel costs. 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 atmosphere. As a result, we cannot currently predict the impact of these potential regulations on our liquidity, financial position, or results of operations.

Other Air Emissions

In February 2024, EPA released a final rule to lower the primary (health-based) fine particulate matter annual standard from its current level of 12.0 µg/m3 to 9.0 µg/m3. Lowering of the National Ambient Air Quality Standards (“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. 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. These new requirements will replace the Regional Clean Air Incentives Market (“RECLAIM”) cap-and-trade program which has required a staged refinery-wide reduction of NOx emissions over the last several years and will result in additional emission reductions from our Los Angeles Refinery. Compliance with Rule 1109.1 is being phased in through 2032 and will result in increased costs to operate and maintain our Los Angeles Refinery.

Water

We maintain numerous 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. 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.

On October 22, 2019, EPA and the United States Army Corps of Engineers (“Army Corps”) published a final rule to repeal the 2015 “Clean Water Rule: Definition of Waters of the United States” (“2015 Rule”), which amended portions of the Code of Federal Regulations to restore the regulatory text that existed prior to the 2015 Rule, effective December 23, 2019. The rule repealing the 2015 Rule has been challenged in multiple federal courts. On April 21, 2020, EPA and the Army Corps promulgated the Navigable Waters Protection Rule (“2020 Rule”) to define “waters of the United States.” The 2020 Rule has been vacated by a federal court. On January 18, 2023, EPA and the Army Corps published a final rule (“2023 Rule”) repealing the 2020 Rule defining “waters of the United States” and adopting a rule largely based upon the definition adopted in 1986 with some revisions based upon subsequent United States Supreme Court rulings, in particular Rapanos v. United States (2006), which produced two different tests for determining “waters of the United States,” the relatively permanent waters and significant nexus tests. The 2023 Rule has been challenged in multiple federal courts and has been enjoined from applying in 27 states where the pre-2015 “waters of the United States” definition and guidance applies. On May 25, 2023, the United States Supreme Court issued its decision in Sackett v. EPA rejecting the significant nexus test in favor of the relatively permanent waters test, thereby narrowing the scope of wetlands and other water bodies regulated as “waters of the United States.” On September 8, 2023, EPA and the Army Corps revised the 2023 Rule to conform to the Sackett decision (“Revised 2023 Rule”). The Revised 2023 Rule applies in only 23 states and has also been challenged in multiple federal courts. The regulatory uncertainty could result in delays in permitting and impact pipeline construction and maintenance activities.

In April 2020, the U.S. District Court in Montana vacated Nationwide Permit 12 (“NWP 12”), which authorizes the placement of fill material in “waters of the United States” for utility line activities as long as certain best management practices are implemented. The decision was ultimately appealed to the United States Supreme Court, which partially reversed the district court’s decision, temporarily reinstating NWP 12 for all projects except the Keystone XL oil pipeline. The Army Corps subsequently reissued its nationwide permit authorizations on January 13, 2021, by dividing the NWP that authorizes utility line activities (NWP 12) into three separate NWPs that address the differences in how different utility line projects are constructed, the substances they convey, and the different standards and best management practices that help ensure those NWPs authorize only those activities that have no more than minimal adverse environmental effects. A challenge of the 2021 authorization is currently pending before the U.S. District Court for the District of Columbia (“D.D.C.”), after being transferred from the U.S. District Court for the District of Montana in August 2022, and the plaintiffs request the court vacate and remand the 2021 authorization. Also, a petition has been filed with the Army Corps asking it to revoke the 2021 authorization. The Army Corps could repeal or replace the 2021 authorization in a subsequent rulemaking, and proposed modifications to NWP 12 are expected to be published for notice and comment in early 2024. The repeal, vacatur, revocation or modification of the 2021 authorization could impact pipeline construction and maintenance activities.

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.

In May 2016, 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 EPA also issued HALs for two additional PFAS substances. In February 2019, EPA issued a PFAS Action Plan identifying actions it is planning to take to study and regulate various PFAS chemicals. 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 listing PFOA and PFOS as hazardous substances under CERCLA, and (4) conducting toxicity assessments for other PFAS chemicals. On December 5, 2022, EPA issued to states and EPA regional offices a memorandum providing guidance for addressing PFAS discharges in wastewater and stormwater. Also, on March 29, 2023, EPA issued a notice of proposed rulemaking to establish national drinking water standards for PFOS, PFOA, perfluorohexane sulfonic acid, perfluorononanoic acid, perfluorobutane sulfonic acid (“PFBS”), and hexafluoropropylene oxide dimer acid and its ammonium salt (also known as “GenX”). EPA indicates it will issue a final rule in late 2024. Congress may also take further action to regulate PFAS. We cannot currently predict the impact of potential statutes or 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 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 hazardous wastes in our operations. RCRA establishes standards for the management of solid and hazardous wastes. 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, terminal and pipeline 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.

On September 6, 2022, EPA issued a notice of proposed rulemaking that would designate PFOS and PFOA as hazardous substances under CERCLA Section 102(a). EPA indicates it will issue a final action during the first quarter of 2024. In addition, 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 addition, EPA establishes carbon dioxide (“CO2”) emission standards for passenger cars and light trucks. An Executive Order issued on August 5, 2021, set a goal that 50 percent of all new passenger cars and light trucks sold in 2030 be zero emission vehicles. Consistent with this order, EPA and NHTSA have promulgated separate rules setting more stringent requirements. NHTSA’s CAFE standards would increase in stringency from model year 2023 levels by eight percent annually for model years 2024-2025 and ten percent annually for model year 2026. EPA’s model year 2023-2026 CO2 emission standards result in average fuel economy of 40 mpg in model year 2026. These NHTSA and EPA regulations have been challenged in court. In addition, NHTSA and EPA have proposed new rules setting even more stringent requirements for model years 2027-2032. NHTSA’s proposed standards would require an increase in fuel efficiency of two percent annually. EPA’s proposed standards represent a 56 percent reduction in emissions relative to the model year 2026 standards and would require a significant increase in electric vehicle production to meet the standards. Higher CAFE and CO2 emission standards for cars and light trucks reduce demand for our transportation fuels.

In addition, California may establish per its Clean Air Act waiver authority different standards that could apply in multiple states. EPA has issued a rule that reinstates California’s waiver for its Advanced Clean Car I program, which includes requirements for zero emission vehicle sales through 2025. California’s governor has also issued an executive order requiring sales of all new passenger vehicles in the state be zero-emission by 2035. The California Air Resources Board followed this executive order by finalizing its Advanced Clean Car II regulation, which bans the sale of internal combustion engine vehicles in California in 2035. California is seeking a waiver from EPA for its Advanced Clean Car II program. Other states have issued, or may issue, zero emission vehicle mandates.

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 EPA the authority to set the annual volumes. EPA has promulgated annual volumes for 2023-2025 that increase the volume of renewable fuel that must be blended year over year.

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 began implementing its LCFS in January 2011. In September 2015, the CARB approved the re-adoption of the LCFS, which became effective on January 1, 2016, to address procedural deficiencies in the way the original regulation was adopted. The LCFS was amended again in 2018 with the current version targeting a 20 percent reduction in fuel carbon intensity from a 2010 baseline by 2030. CARB has issued a proposed rule expected to be finalized in early 2024 that would increase the stringency of the carbon intensity targets for 2025 and beyond. We incur costs to comply with LCFS programs, and these costs may increase if the cost of LCFS 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 (“PSM”) and 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. EPA has proposed revisions to its RMP regulation. The proposed 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.

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 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.

Certain of our facilities are subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which expired on July 28, 2023. Congress has introduced bills that, if passed, would extend the program. We also 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.

Tribal Lands

Various federal agencies, including 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, 2023, we employed approximately 18,200 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 metrics include several employee, process and environmental safety metrics.

Talent Management

Our People Strategy holistically addresses the dynamic business environment we operate in. It enables us to be an employer of choice with the best people and the right capabilities supporting our inclusive culture. Executing our People Strategy requires that we attract and retain the best talent. Attracting and retaining top talent involves presenting new employees with the tools for success and providing opportunities for long-term engagement and career advancement. 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 diverse 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 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, 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

Our People Strategy also includes our Diversity, Equity and Inclusion ("DE&I") program guided by a dedicated team of subject matter experts and supported by leadership. Our program is based on our three-pillar DE&I strategy of building a diverse workforce, creating an inclusive culture and contributing to our thriving communities.

We promote cultural inclusivity and respect among our employees. We recognize that when employees feel valued, it shows in their performance. Our employee networks are fundamental to achieving this goal and connect employees with others who have a shared identity and life experiences. These seven groups use a member and ally model to promote inclusion - Asian, Black, Hispanic, LGBTQ+, Veterans, Women and People with Disabilities. 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 the executive officers and corporate officers of MPC:

* Corporate officer.

Mr. Hennigan was appointed Chief Executive Officer, effective January 1, 2024, having previously served as President and Chief Executive Officer since March 2020. He has served as a member of the Board of Directors since April 2020. Mr. Hennigan also has served as Chairman of the Board of MPLX since April 2020, as Chief Executive Officer since November 2019 and as President since June 2017. Before joining MPLX, Mr. Hennigan was President, Crude, NGL and Refined Products, of the general partner of Energy Transfer Partners L.P., an energy service provider. He was President and Chief Executive Officer of Sunoco Logistics Partners L.P., an oil and gas transportation, terminalling and storage company, from 2012 to 2017, President and Chief Operating Officer beginning in 2010, and Vice President, Business Development, beginning in 2009.

Ms. Mannen was appointed President, effective January 1, 2024, having previously served as Executive Vice President and Chief Financial Officer since January 2021. She also has served as a member of MPLX’s Board of Directors since February 2021. Before joining MPC, she served as Executive Vice President and Chief Financial Officer of TechnipFMC (a successor to FMC Technologies, Inc.), a leading global engineering services and energy technology company, since 2017, having previously served as Executive Vice President and Chief Financial Officer of FMC Technologies, Inc. since 2014, Senior Vice President and Chief Financial Officer since 2011, and in various positions of increasing responsibility with FMC Technologies, Inc. since 1986.

Mr. Quaid was appointed Executive Vice President and Chief Financial Officer, effective January 1, 2024, having previously served as MPLX’s Executive Vice President and Chief Financial Officer since September 2021. He also has served as a member of MPLX’s Board since January 2022. Prior to his 2021 appointment at MPLX, Mr. Quaid served as our Senior Vice President and Controller beginning in April 2020, and Vice President and Controller beginning in 2014. Before joining MPC, Mr. Quaid was Vice President of Iron Ore at United States Steel Corporation, an integrated steel producer, beginning in 2014, and Vice President and Treasurer beginning in 2011, having previously served in various functions including investor relations, business planning, financial planning and analysis and project management.

Mr. Aydt was appointed Executive Vice President Refining, effective October 2022, having previously served as Executive Vice President and Chief Commercial Officer of MPLX since August 2020. Prior to his 2020 appointment, he served as Vice President, Business Development, beginning in November 2018, Vice President, Operations, and President of Marathon Pipe Line LLC beginning in January 2017, MPC’s Terminal, Transport and Rail General Manager beginning in 2013, and Project Director for the $2.2 billion Detroit Heavy Oil Upgrade Project beginning in 2008.

Ms. Benson was appointed Chief Legal Officer and Corporate Secretary, effective January 1, 2024, having previously served as Vice President, Chief Securities, Governance & Compliance Officer and Corporate Secretary since June 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 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 since February 2018. Before joining Andeavor, Ms. Laird was Chief Human Resources and Communications Officer for Newell Brands, a global consumer goods company, beginning in May 2016 and Executive Vice President, Human Resources, for Unilever, a global consumer goods company, beginning in 2011.

Mr. Heppner was appointed Senior Vice President Strategy and Business Development, effective February 2021. Prior to this appointment, he served as Vice President, Commercial and Business Development, beginning in October 2018, Senior Vice President of Engineering Services and Corporate Support of Speedway LLC beginning in 2014, and Director, Wholesale Marketing, beginning in 2010.

Mr. Hessling was appointed Chief Commercial Officer, effective January 1, 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 October 2018, Manager, Crude Oil & Natural Gas Supply and Trading, beginning in 2014, and Crude Oil Logistics & Analysis Manager beginning in 2011.

Mr. Partee was appointed Chief Global Optimization Officer, effective January 1, 2024, having previously served as Senior Vice President, Global Clean Products, since February 2021. Prior to his 2021 appointment, he served as Senior Vice President, Marketing, beginning in October 2018, Vice President, Business Development, beginning in February 2018, Director of Business Development beginning in January 2017, Manager of Crude Oil Logistics beginning in 2014, and 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 served as 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 April 2018, having previously served as Senior Vice President and CIO, Services, of GE, a multinational conglomerate, since January 2017 and CIO, Power Services, with GE Power since 2014, and in various positions of increasing responsibility with GE and its subsidiaries since 2000.

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 October 2018, Director, Environment, Safety, Security and Product Quality, beginning in February 2016, and Director, Refining Environmental, Safety, Security and Process Safety Management, beginning in 2013.

Ms. Brzezinski was appointed Vice President and Controller, effective January 8, 2024. Prior to this appointment, she served as Assistant Controller, Technical Accounting, since August 2021, having previously served as Manager, Accounting, since May 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. Prior to this appointment, she served as Vice President, Investor Relations, beginning in April 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 September 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, Corporate Finance Manager beginning in October 2014, and 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 the 2020 appointment, he served as Executive Vice President, Gathering and Processing, beginning in 2018, Executive Vice President and Chief Operating Officer, MarkWest Operations, beginning in July 2017, and Executive Vice President and Chief Commercial Officer, MarkWest Assets, beginning in 2015, at the time of MPLX’s 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, Mr. Floerke held senior management positions at Access Midstream Partners, L.P. from 2011 until 2013.

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 November 2018. Prior to his 2018 appointment, he was 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 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 at www.marathonpetroleum.com (http://www.marathonpetroleum.com) under the “Investors” tab by selecting “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 at this site under the “About” tab by selecting “Board of Directors.”

MPC uses its website, www.marathonpetroleum.com (http://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 at www.sec.gov (http://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.

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. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized.

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 continue the payment of our base dividend are highly dependent on the margins we realize on our refined products. Historically, refining and marketing margins have been volatile, and we believe they will continue to be volatile. Our margins from the sale of gasoline and other 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:

• worldwide and domestic supplies of and demand for feedstocks and refined products;
• transportation infrastructure cost and availability;
• operation levels of other refineries in our markets;
• the development by competitors of new refining or renewable conversion capacity;
• natural gas and electricity supply costs;
• political instability, threatened or actual terrorist incidents, armed conflict or other global political or economic conditions;
• 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 refining and marketing 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 refining and marketing 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 refining and marketing 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 practices regarding our repurchase activity and dividends.

Legal, technological, political and scientific developments regarding emissions, fuel efficiency and alternative fuel vehicles may decrease demand for petroleum-based transportation fuels.

Developments aimed at reducing vehicle emissions, increasing vehicle efficiency or reducing the sale of new petroleum-fueled vehicles may decrease the demand and may increase the cost for our transportation fuels. An Executive Order issued on August 5, 2021, set a goal that 50 percent of all new passenger cars and light trucks sold in 2030 be zero emission vehicles. Consistent with this order, EPA and NHTSA have promulgated separate rules setting more stringent requirements for reductions through model year 2026. NHTSA’s amended CAFE standards increase in stringency from model year 2023 levels by eight percent annually for model years 2024-2025 and ten percent annually for model year 2026. EPA’s revised model year 2023-2026 CO2 emission standards, which were finalized in December 2021, result in average fuel economy of 40 mpg in model year 2026. Other jurisdictions have issued or considered issuing similar mandates, and we expect this trend will continue.

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 such as hydrogen or ammonia, or efficiency improvements for internal combustion engines could reduce demand for petroleum-based transportation fuels.

Together, these trends and developments have had and are expected to continue to have an adverse effect on sales of our petroleum-based 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 such an incident 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 owned by MPC and MPLX. 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 personally identifiable information such as employee, customer and investor 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, and phishing and social engineering schemes, supply chain attacks, and advanced artificial intelligence cyberattacks, 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. Because the techniques used to obtain unauthorized access, or to disable or degrade systems continuously evolve and 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.

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 of varying degrees. To date, the impacts of prior events have not had a material adverse effect on us.

Cybersecurity events 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, regulated personally identifiable information, intellectual property and other information; give rise to remediation or other expenses; result in litigation, claims and increased regulatory review 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. Any of such results could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.

The availability and cost of renewable identification numbers could have an adverse effect on our financial condition and results of operations.

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. A RIN is assigned to each gallon of renewable fuel produced in, or imported into, the United States. 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 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. We are exposed to the volatility in the market price of RINs. We cannot predict the future prices of RINs. RINs prices are dependent upon a variety of factors, including EPA regulations, the availability of RINs for purchase, 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 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. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies. Continuing 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 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.

Decreases in energy prices can lead to decreases in 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, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices can result in producers deciding to limit their oil and gas drilling operations, which can 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 due to the extent of MPLX’s commodity-based contracts, 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 our Midstream operations to volatility in natural gas or NGL prices due to the potential difference in the time of the purchases and sales and the potential difference in the price associated with each transaction, and direct exposure may also occur naturally as a result of production processes. Also, the significant volatility in natural gas, NGL and 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 risks, such as sea-level rise or water shortages. For example, in 2021, our Galveston Bay refinery was adversely affected by Winter Storm Uri and our Garyville refinery was adversely affected by Hurricane Ida. 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 new 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 acquisitions or 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, 2023, our total debt obligations for borrowed money and finance lease obligations were $27.62 billion, including $20.71 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:

• 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 petroleum products, could have significant and adverse consequences for our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity, trigger additional impairments and negatively affect 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 share price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make 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 rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to make 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.

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, 2023, our balance sheet reflected $8.2 billion and $1.8 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.

We have several large capital projects underway, including efficiency and modernization improvements at our Los Angeles Refinery and a Distillate Hydrotreater project at our Galveston Bay Refinery. 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 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.

Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we may not receive any material increases in revenues until after completion of the project, if at all.

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 or other laws or regulations. Future environmental laws and regulations may impact our current business plans and reduce demand for our products and services.

Our business is subject to numerous environmental laws and regulations. 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 quantity of renewable fuels that must be blended into transportation fuels;
• public and employee safety and health;
• permitting;
• inherently safer technology; and
• 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 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.

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, the President and members of the U.S. Congress propose and consider substantive changes to 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 results of operations and financial condition.

Currently, multiple legislative and regulatory measures to address GHG (including carbon dioxide, methane and nitrous oxides) 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 cap-and-trade programs. 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.

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.

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.

International climate change-related efforts, such as the 2015 United Nations Conference on Climate Change, which led to the creation of the Paris Agreement, may impact the regulatory framework of states whose policies directly influence our present and future operations. In the United States, an Executive Order issued on January 27, 2021, announced putting the U.S. on a path to achieve net-zero carbon emissions, economy-wide, by 2050. The Executive Order also calls for the federal government to pause oil and gas leasing on federal lands and reduce methane emissions from the oil and gas sector as quickly as possible, and requires federal permitting decisions to consider the effects of GHG emissions and climate change. In December 2023, EPA completed one provision of the order by promulgating a final rule to reduce methane and volatile organic compounds from oil and gas operations. Concurrently, EPA significantly increased the social cost of greenhouse gases. A higher social cost of greenhouse gases could support more stringent GHG emission regulation.

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, has been 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 diversity, equity 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. In 2022, MPC established a target to reduce GHG emissions 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 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, including the SEC’s proposed disclosure requirements regarding, among other matters, GHG emissions, 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. For example, in 2015, the U.S. Department of Transportation issued new standards and regulations applicable to crude-by-rail transportation (Enhanced Tank Car Standards and Operational Controls for High-Hazard Flammable Trains). These or other 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 the crude oil we purchase, 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 from production areas to our refineries, increase the cost of rail transportation and decrease the efficiency of shipments of crude oil by rail within our operations. 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 or (ii) impose restrictions on turnaround and maintenance activities, 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, “SBx 1-2”) 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 (e.g., daily, weekly, monthly, and annually reporting of detailed operational and financial data on all aspects of our operations in California) 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 analyze the data provided under SBx 1-2, 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 fuels 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 SBx 1-2, and (ii) an order initiating rulemaking activity under SBx 1-2 that will be focused on refinery maintenance and turnarounds.

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, 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 SBx 1-2 will have on our California operations or our company nor can we predict the impact from similarly focused legislation or actions in other jurisdictions in which we operate our refineries. 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.

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, processing and fractionation services with respect to natural gas and natural gas liquids produced by our customers as a result of such operations. Our refineries are also supplied in part with crude oil produced from unconventional oil shale reservoirs. 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, 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 and civil claims by private plaintiffs 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 2024 to 2027. 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 2024, there are two collective bargaining agreements, one expired on January 31 and the other will expire on April 7. These two agreements cover approximately 500 employees in refining. The parties to the expired agreement continue operating under the relevant terms of the expired agreement while negotiating a successor agreement. In the event of a work stoppage impacting operations, we have a contingency plan in place to continue operations.

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 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 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 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;
• 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.

Future acquisitions 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.

Future transactions 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, and the Inflation Reduction Act of 2022, 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.

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.

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 cybersecurity risks 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 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 periodical assessment of our cybersecurity program 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, protect, detect, respond and recover from 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 28, 2024, we do not believe that any past cybersecurity incidents have had, or are reasonably likely to have, a material adverse effect on the company, including our business, 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 these events may occur and could have a material adverse effect on our business, 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 has delegated to the Audit Committee of our Board oversight of 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 provides regular cybersecurity briefings to the Board of Directors and the Audit Committee as needed, with a minimum of two briefings per year. The Audit Committee further reviews and provides input on our cybersecurity and information security strategy.

Our CISO is responsible for the cybersecurity program which is comprised of Cybersecurity GRC (Governance, Risk & Compliance), Cybersecurity Architecture, Operations & Engineering, and a Cyber Fusion Center that includes Threat Intelligence, Vulnerability Management, & Incident Response. Our CISO has 30 years of experience in the oil and gas industry and has held various leadership and strategic roles across IT, software R&D and marketing.

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.

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, 2023. 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.

The Dickinson, North Dakota, renewable fuels facility has the capacity to produce 184 million gallons per year of renewable diesel from corn oil, soybean oil, fats and greases. The design capacity of the Martinez facility, a renewable diesel facility, is up to 730 million gallons per year. The Dickinson facility is included within the Mid-Continent region and the Martinez facility is included within the West Coast region.

The following table sets forth the approximate number of locations where jobbers maintain branded outlets, marketing fuels under the Marathon, ARCO, Shell, Mobil, Tesoro and other brands, as of December 31, 2023.

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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, 2023.

The following table sets forth details about our Refining & Marketing owned and operated terminals as of December 31, 2023. See the Midstream - MPLX section for information with respect to MPLX owned and operated terminals.

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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, 2023.

(a) Includes approximately 16 miles of crude oil pipeline and 2 miles of refined product pipeline leased from third parties.

(b) Includes approximately 1,192 miles of inactive crude oil pipeline and 201 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% and 50%, respectively.

(d) Refining logistics assets primarily include tankage. MPC formed the Martinez Renewables joint venture and began producing renewable diesel at the Martinez facility in 2023. MPLX owns refining logistics assets with 5,977 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 logistics services for the facility.

The following table sets forth information regarding the pipeline systems which MPLX has an interest in through ownership of its equity method investments as of December 31, 2023.

(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 15 percent indirect interest in a joint venture that has partial ownership of the Wink to Webster pipeline system.

(c) Whistler Pipeline LLC also owns a 50 percent interest in a joint venture owning primarily natural gas storage facilities.

(d) BANGL LLC also owns a 42 percent interest in a 323 mile NGL pipeline.

The following table sets forth details about MPLX owned and operated terminals as of December 31, 2023. Additionally, MPLX has partial ownership interest in one terminal.

(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, 2023.

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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, 2023.

(a) Natural gas throughput is a weighted average for 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 159 MMcf/d representing MPLX’s share of processed volumes is also included and used to compute the utilization presented above.

(c) Includes volumes processed at third-party facilities in the Bakken.

(a) NGL throughput is a weighted average for 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 77 thousand barrels of condensate storage that is owned by a joint venture in which it has a 62 percent ownership interest. Actual NGL throughput at this facility was 13 mbpd for the year ended December 31, 2023.

(a) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(a) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(b) Includes 102 MMcf/d of volumes gathered for third parties by MPLX’s operated joint venture, Rendezvous Gas Services, L.L.C. (“RGS”). Excludes RGS gathering capacity of 1,032 MMcf/d and volumes gathered by RGS which generally interconnect with MPLX owned Rockies region gathering systems.

The following table sets forth certain information relating to MPLX’s NGL pipelines as of December 31, 2023.

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, 2023, we had partial ownership interests in the following pipeline companies.

(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, 2023.

(a) Represents ownership through our indirect noncontrolling 50 percent interest in Crowley Blue Water Partners.

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.

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.

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. Similar lawsuits may be filed in other jurisdictions. The names of the courts in which the proceedings are pending and the dates instituted are as follows:

Dakota Access Pipeline

MPLX holds a 9.19 percent indirect interest in a joint venture (“Dakota Access”) which owns and operates the Bakken Pipeline system. In 2020, 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 a draft EIS in September 2023 detailing various options for the easement, including denying the easement, approving the easement with additional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has not selected a preferred alternative, but will make a decision in its final review, after considering input from the public and other agencies. The pipeline remains operational while the Army Corps finalizes its decision which is expected to be issued by the end of 2024.

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 to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of construction of the Bakken Pipeline system.

If the vacation 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 shutdown. 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 vacation 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 one percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of December 31, 2023, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $170 million.

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 that crosses the Fort Berthold Reservation in North Dakota. 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, in December 2020, 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 direct 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. On February 8, 2022, the U.S. Government Parties filed their answer and counterclaims to THPP’s suit claiming THPP is in continued trespass with respect to the pipeline and seek disgorgement of pipeline profits from June 1, 2013 to present, removal of the pipeline and remediation. On November 8, 2023, the Court granted THPP’s motion to sever and stay the U.S. Government Parties’ counterclaims. 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. THPP continues not to operate the portion of the pipeline that crosses the property at issue.

Martinez Refinery

On October 20, 2023, Tesoro Refining & Marketing Company LLC, an indirect wholly owned subsidiary of MPC, received an offer to settle 59 Notices of Violation (“NOVs”) received from the Bay Area Air Quality Management District. The NOVs were issued for alleged violations of air quality regulations at our Martinez refinery between June 2018 and May 2022. 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.

Edwardsville Incident

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” line near Edwardsville, Illinois. In September 2023, the U.S. Department of Justice and 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 amount of any civil penalty or 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.

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

For the year ended December 31, 2023, our results were impacted by market prices and seasonal market fluctuations; however, the demand environment in which our business operates remains strong. Global energy markets continue to experience disruptions resulting from regional conflicts, such as in the Middle East and Ukraine. We are unable to predict the potential effects that the continuance or escalation of these military conflicts, and related sanctions or market disruptions on shipping and energy costs, may have on our financial position and results. It remains uncertain how long these conditions may last or how severe they may become.

In June 2023, the provisions of California legislature adopted SBx 1-2 became effective, which authorizes the CEC to establish a “maximum gross gasoline refining margin” with respect to refining activities in California, as well as establish fees for refiners for exceeding the yet to be issued margin cap. The law further expands on existing reporting requirements for refiners to the CEC. In late 2023, the CEC adopted (i) an order requiring an informational proceeding on a maximum gross gasoline refining margin and penalty under SBx 1-2, and (ii) an order initiating rulemaking activity under SBx 1-2 that will be focused on refinery maintenance and turnarounds. We will evaluate the impact that SBx1-2 and any associated forthcoming CEC regulations may have on our current or anticipated future operations in California and results of operations when SBx 1-2 is fully implemented.

In response to the current business environment, we continue to focus on the following priorities for our business:

Strengthen Competitive Position of Assets

We are committed to positioning our assets so that we are a leader in operational, financial, and sustainability performance and are evaluating the strength and fit of assets in our portfolio. Our goal is 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.

Improve Commercial Performance

We are focused on leveraging advantaged raw material selection, new approaches in the commercial space to be more dynamic amidst changing market conditions and achieving technology improvements to advance our commercial performance. A near-term focus has been securing advantaged renewable feedstocks as we continue to advance our renewable fuels production capabilities. This includes exploring joint venture opportunities and strategic alliances within the renewable fuels value chain.

Continued Capital Discipline and Focus on Low-Cost Culture

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.

Commitment to Sustainability

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. Specifically, in 2022, we were the first among U.S. independent refiners to establish a 2030 target to reduce absolute Scope 3 - Category 11 GHG emissions. This goal added to our existing targets for reducing Scope 1 & 2 GHG emissions intensity, for lowering methane emissions intensity and for lowering our freshwater withdrawal intensity. Additionally, MPLX is progressing towards meeting its 2025 and 2030 methane intensity reduction goals, as well as its biodiversity target, by applying sustainable landscapes to its compatible right of ways.

Strategic Updates

MPLX Acquisition of 40 percent Interest in Gathering and Processing Joint Venture

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, MPLX now owns 100 percent of Torñado and reflects it as a consolidated subsidiary within 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.

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, MPLX’s existing equity investment was remeasured to fair value resulting in the recognition of a $92 million gain.

Green Bison Soy Processing LLC Facility (“Green Bison Soy Processing”)

In November 2023, Green Bison Soy Processing, a dedicated soybean processing complex, opened in Spiritwood, North Dakota. The facility is North Dakota's first dedicated soybean processing complex, and is a major step towards meeting increased demand for renewable fuels, in this case renewable green diesel. Green Bison Soy Processing will source and process local soybeans, with the resulting oil supplied exclusively to MPC as a feedstock for renewable fuels. The facility will produce approximately 600 million pounds of refined soybean oil annually, enough feedstock for approximately 75 million gallons of renewable green diesel per year. The approximately $350 million complex, which features state-of-the-art automation technology, is in the commissioning and startup phase of processing soybeans for meal and oil. The facility is a joint venture with ADM owning 75 percent and MPC owning 25 percent.

South Texas Gateway Terminal LLC

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.

LF Bioenergy Acquisition

On March 8, 2023, MPC announced the acquisition of a 49.9 percent equity interest in LF Bioenergy, an emerging producer of 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. Current projects are under various stages of development, with the first facility reaching full commercial operation in the first half of 2023. LF Bioenergy's management and origination teams continue to expand the portfolio with additional sanctioned projects while progressing their existing pipeline of opportunities toward final investment decisions. As specific project milestones are achieved, MPC is expected to fund its share of capital expenditures to build out the portfolio.

Martinez Renewables Joint Venture

The Martinez Renewables facility, which has a design capacity of 730 million gallons per year including pretreatment capabilities, began ramping up production of renewable diesel in 2023.

Share Repurchase Authorization

On October 25, 2023, MPC announced that our board of directors approved an additional $5.0 billion share repurchase authorization in addition to the $5.0 billion share authorizations announced on January 31, 2023 and May 2, 2023. As of December 31, 2023, MPC had $6.78 billion remaining under its share repurchase authorizations. Future repurchases under the authorizations will depend on the macro environment, cash available after opportunities for capital investment and growth of the business and market conditions. The authorizations have no expiration date.

Other

Succession Planning

As previously disclosed, MPC maintains a mandatory retirement policy that, absent a waiver or extension, requires an executive officer to retire from service to the company coincident with, or immediately following, the first of the month after such executive officer reaches age 65 (the "Policy"). Michael J. Hennigan, our Chief Executive Officer, will reach mandatory retirement on August 1, 2024. Accordingly, the MPC Board of Directors, with a focus on the long-term strategic direction of the company, is engaged in appropriate succession planning activities, which are expected to include, among other customary steps, the review of succession candidates, as well as consideration of any waiver or extension of the Policy respecting Mr. Hennigan.

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 2023 and 2022 are reflected in the following table.

(a) 2023 includes 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 and the $106 million gain on the sale of our interest in South Texas Gateway. 2022 includes the $549 million gain related to the contribution of assets by MPC on the formation of the Martinez Renewables joint venture and the $509 million gain on lease reclassification. See Item 8. Financial Statements and Supplementary Data - Notes 15 and 27.

(b) Represents retroactive changes in renewable volume obligation requirements published by EPA in June 2022 for the 2020 and 2021 annual obligations.

The following table includes net income per diluted share data.

Net income attributable to MPC decreased $4.84 billion, or $4.49 per diluted share, in 2023 compared to 2022 primarily due to lower Refining & Marketing margins and net gain on the disposal of assets.

See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on discontinued operations.

Refer to the Results of Operations section for a discussion of financial results by segment for the three years ended December 31, 2023.

MPLX

We received limited partner distributions of $2.06 billion and $1.87 billion from MPLX during 2023 and 2022, respectively. We owned approximately 647 million MPLX common units at December 31, 2023 with a market value of $23.77 billion based on the December 29, 2023 closing unit price of $36.72. On January 24, 2024, MPLX declared a quarterly cash distribution of $0.8500 per common unit, which was paid February 14, 2024. As a result, MPLX made distributions totaling $853 million to its common unitholders. MPC’s portion of these distributions was approximately $550 million.

During the year ended December 31, 2023, no MPLX units were repurchased. As of December 31, 2023, $846 million remained available under the authorization for future repurchases.

On February 9, 2023, MPLX issued $1.1 billion aggregate principal amount of 5.00 percent senior notes due 2033 and $500 million aggregate principal amount of 5.65 percent senior notes due 2053 in an underwritten public offering.

On February 15, 2023, MPLX redeemed all of the 600,000 outstanding Series B preferred units at the redemption price of $1,000 per unit. The semi-annual distribution due to Series B unitholders on February 15, 2023, was also paid on that date, in the usual manner. On March 13, 2023, MPLX redeemed all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023.

See Item 8. Financial Statements and Supplementary Data – Note 6 for additional information on MPLX.

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 2,950 mbpcd, 2,898 mbpcd and 2,887 mbpcd as of December 31, 2023, 2022 and 2021, 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.

(a) Crack spread based on 40 percent MEH, 40 percent WTI and 20 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 2024 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 2024 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 charges due to changes in historic inventory levels; and
• the cost of purchasing RINs in the open market to comply with RFS2 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, 2023, market values for refined products 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 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, 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.

RESULTS OF OPERATIONS

The following discussion includes comments and analysis relating to our results of operations for the years ended December 31, 2023, 2022 and 2021. 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

(a) In accordance with discontinued operations accounting, Speedway sales to retail customers and net results are reflected in Income from discontinued operations, net of tax, and Refining & Marketing intercompany sales to Speedway are presented as third-party sales through the close of the sale on May 14, 2021.

2023 Compared to 2022

Net income attributable to MPC decreased $4.84 billion in 2023 compared to 2022, primarily due to lower Refining & Marketing margins and net gain on the disposal of assets.

Total revenues and other income decreased $29.65 billion in 2023 compared to 2022 primarily due to:

• decreased sales and other operating revenues of $29.07 billion primarily due to decreased average refined product sales prices of $0.52 per gallon, or 17 percent, partially offset by increased refined product sales volumes of 28 mbpd, or 1 percent;
• increased income from equity method investments of $87 million largely due to increased income from Midstream equity affiliates, partially offset by decreased income from Refining & Marketing equity affiliates;
• decreased net gains on disposal of assets of $844 million mainly due to gains of $549 million on the formation of the Martinez Renewables joint venture and $509 million on a lease reclassification in 2022, partially offset by 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 Torñado, arising from the acquisition of the remaining 40 percent interest in 2023; and
• increased other income of $186 million largely due to the receipt of insurance proceeds, partially offset by lower income on RIN sales.

Total costs and expenses decreased $22.69 billion in 2023 compared to 2022 primarily due to:

• decreased cost of revenues of $23.11 billion primarily due to lower crude oil costs;
• increased depreciation and amortization of $92 million mainly due to assets placed in service;
• increased selling, general and administrative expenses of $267 million primarily due to increased employee compensation and related expenses, contract services and software maintenance costs; and
• increased other taxes of $56 million largely due to the reinstated Petroleum Superfund Tax, which was effective January 1, 2023.

Net interest and other financial costs decreased $475 million largely due to increased interest income, primarily on short-term investments, and decreased pension non-service costs, partially offset by increased interest expense due to higher MPLX borrowings. We capitalized interest of $60 million in 2023 and $104 million in 2022. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.

We recorded a combined federal, state and foreign income tax expense 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. We recorded a combined federal, state and foreign income tax expense of $4.49 billion for the year ended December 31, 2022, which was higher than the tax computed at the U.S. statutory rate primarily due to state taxes, partially offset by permanent tax benefits related to net income attributable to noncontrolling interests.

Net income attributable to noncontrolling interests decreased $49 million mainly due to MPLX’s redemption of its outstanding Series B preferred units on February 15, 2023.

2022 Compared to 2021

Net income attributable to MPC increased $4.78 billion in 2022 compared to 2021 primarily due to increased average refined product sales prices and volumes and net gains on the disposal of assets, partially offset by increased operating costs and the absence of a gain on the sale of Speedway and a partial period of income from discontinued operations due to the sale of the Speedway business on May 14, 2021.

Total revenues and other income increased $59.02 billion in 2022 compared to 2021 primarily due to:

• increased sales and other operating revenues of $57.47 billion primarily due to increased average refined product sales prices of $0.96 per gallon, or 47 percent, and refined product sales volumes of 83 mbpd, or 2 percent, largely due to continuing recovery in demand for our products across all our regions;
• increased income from equity method investments of $197 million largely due to increased income from Midstream equity affiliates;
• increased net gains on disposal of assets of $1.04 billion mainly due to a gain of $549 million on the formation of the Martinez Renewables joint venture and a gain of $509 million on a lease reclassification; and
• increased other income of $315 million primarily due to higher income on RIN sales.

Total costs and expenses increased $41.85 billion in 2022 compared to 2021 primarily due to:

• increased cost of revenues of $41.66 billion primarily due to higher crude oil costs and finished product purchases;
• decreased depreciation and amortization of $149 million mainly due to 2021 Midstream asset impairments and assets that were fully depreciated in 2021;
• increased selling, general and administrative expenses of $235 million mainly due to increased salaries, benefits and employee related expenses, credit card processing fees, contract services and insurance; and
• increased other taxes of $104 million largely due to retroactive operating tax assessments for prior periods.

Net interest and other financial costs decreased $483 million largely due to increased interest income, decreased debt retirement expenses related to the redemption of MPC senior notes in 2021, decreased interest expense due to lower MPC borrowings and decreased pension and other postretirement non-service costs, partially offset by increased interest expense due to higher MPLX borrowings. We capitalized interest of $104 million in 2022 and $73 million in 2021. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.

We recorded a combined federal, state and foreign income tax expense of $4.49 billion for the year ended December 31, 2022, which was higher than the tax computed at the U.S. statutory rate primarily due to state taxes, partially offset by permanent tax benefits related to net income attributable to noncontrolling interests. We recorded a combined federal, state and foreign income tax expense of $264 million for the year ended December 31, 2021, which was lower than the tax computed at the U.S. statutory rate primarily due to certain permanent tax benefits related to net income attributable to noncontrolling interests and a change in benefit related to the net operating loss carryback provided under the Coronavirus Aid, Relief, and Economic Security Act, partially offset by state taxes. See Item 8. Financial Statements and Supplementary Data – Note 13 for further details.

Net income attributable to noncontrolling interests increased $283 million mainly due to an increase in MPLX’s net income.

Segment Results

We classify our business in the following reportable segments: Refining & Marketing and Midstream. 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 $19.72 billion, $25.03 billion and $8.93 billion for the years ended December 31, 2023, 2022 and 2021, respectively. The following shows the percentage of segment adjusted EBITDA by segment for the last three years.

Refining & Marketing

The following includes key financial and operating data for 2023, 2022 and 2021.

48

(a) Includes intersegment sales to Midstream and sales destined for export.

(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) Includes income (loss) from equity method investments, net gain (loss) on disposal of assets and other income.

(e) Storms in the first and third quarters of 2021 resulted in higher costs, including maintenance and repairs.

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 EPA renewable volume obligations for attributable products under the Renewable Fuel Standard.

(a) The blended crack spreads for 2023, 2022 and 2021 are 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.

2023 Compared to 2022

Refining & Marketing segment revenues decreased $28.63 billion primarily due to decreased average refined product sales prices of $0.52 per gallon, partially offset by increased refined product sales volumes of 28 mbpd.

Refinery crude oil capacity utilization was 92 percent during 2023 and net refinery throughput decreased 37 mbpd in 2023.

Refining & Marketing segment adjusted EBITDA decreased $5.71 billion primarily driven by decreased per barrel margin and throughput, increased distribution costs, excluding depreciation and amortization, partially offset by increased other income and decreased refining operating costs, excluding depreciation and amortization.

Refining & Marketing margin, excluding LIFO inventory adjustments, was $23.16 per barrel for 2023 compared to $28.10 per barrel for 2022. 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 $6 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 2023, a LIFO inventory charge of $145 million and for 2022, a LIFO inventory credit of $148 million. These factors had an estimated net positive impact on Refining & Marketing segment adjusted EBITDA of approximately $700 million in 2023 compared to 2022.

For the year ended December 31, 2023, refining operating costs, excluding depreciation and amortization, were $5.75 billion. This was a decrease of $83 million, compared to the year ended December 31, 2022, largely due to lower energy costs, partially offset by higher project expense. These expenses relate to projects that are regularly performed during refinery turnarounds, of which we had more in 2023, compared to 2022.

Distribution costs, excluding depreciation and amortization, were $5.71 billion and $5.27 billion for 2023 and 2022, respectively, and include fees paid to MPLX of $3.84 billion and $3.65 billion for 2023 and 2022, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, increased $0.48 primarily due to higher pipeline tariff rates and logistics fee escalations.

Refining planned turnaround costs increased $79 million, or $0.09 per barrel, due to the scope and timing of turnaround activity.

Depreciation and amortization per barrel increased by $0.05, primarily due to an increase in costs and a decrease in throughput.

Other income increased by $0.28 per barrel mainly due to the receipt of insurance proceeds in 2023.

We purchase RINs to satisfy a portion of our RFS2 compliance. Our expenses associated with purchased RINs were $2.07 billion in 2023 and $2.40 billion in 2022, including benefits related to retroactive changes in renewable volume obligation requirements, and are included in Refining & Marketing margin. The decrease in 2023 was primarily due to increased RINs acquired with purchased product from third parties and through RINs generated and acquired from our Martinez Renewables joint venture in addition to lower average RINs prices.

2022 Compared to 2021

Refining & Marketing segment revenues increased $56.71 billion primarily due to increased average refined product sales prices of $0.96 per gallon and higher refined product sales volumes, which increased 83 mbpd.

Refinery crude oil capacity utilization was 96 percent during 2022 and net refinery throughputs increased 152 mbpd primarily due to continuing recovery in demand for our products across all our regions.

Refining & Marketing segment adjusted EBITDA increased $15.74 billion primarily driven by higher per barrel margins, partially offset by increased refining operating costs and distribution costs, both excluding depreciation and amortization.

Refining & Marketing margin, excluding LIFO inventory credit of $148 million, was $28.10 per barrel for 2022 compared to $13.36 per barrel for 2021. 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 $18 billion on Refining & Marketing margin, primarily due to higher 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 2022, a LIFO inventory credit of $148 million. These factors had an estimated net negative impact on Refining & Marketing segment adjusted EBITDA of approximately $1.5 billion in 2022 compared to 2021.

For the year ended December 31, 2022, refining operating costs, excluding depreciation and amortization and storm impacts, were $5.83 billion. This was an increase of $708 million, or $0.39 per barrel, compared to the year ended December 31, 2021, primarily due to an increase in energy costs largely as a result of higher natural gas and electricity prices.

Distribution costs, excluding depreciation and amortization, were $5.27 billion and $5.15 billion for 2022 and 2021, respectively, and include fees paid to MPLX of $3.65 billion and $3.47 billion for 2022 and 2021, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, decreased $0.15 due to higher throughput.

Refining planned turnaround costs increased $540 million, or $0.47 per barrel, due to the scope and timing of turnaround activity.

Depreciation and amortization per barrel decreased by $0.11, primarily due to a decrease in costs and an increase in throughput.

We purchase RINs to satisfy a portion of our RFS2 compliance. Our expenses associated with purchased RINs were $2.40 billion in 2022 and $1.49 billion in 2021, including benefits related to retroactive changes in renewable volume obligation requirements, and are included in Refining & Marketing margin. The increase in 2022 was primarily due to higher weighted average RIN costs and an increase in RIN obligations due to higher production.

Supplemental Refining & Marketing Statistics

(a) Based on calendar-day capacity, which is an annual average that includes down time for planned maintenance and other normal operating activities.

(b) Product yields include renewable production.

(c) Represents fully loaded export cargoes for each time period. These sales volumes are included in the total sales volumes amounts.

Midstream

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(a) On owned common-carrier pipelines, excluding equity method investments.

(b) Includes amounts related to MPLX operated unconsolidated equity method investments on a 100 percent basis.

(a) 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.

2023 Compared to 2022

Midstream segment adjusted EBITDA increased $399 million. Sales and operating revenues decreased $82 million mainly due to lower NGL prices, partially offset by rate escalations and higher throughput. This decrease was more than offset by lower purchased product costs of $465 million, primarily due to lower NGL prices of $917 million, partially offset by higher volumes of $405 million, an increase of $47 million due to changes in the fair value of an embedded derivative in a natural gas purchase commitment and an increase in income from equity method investments of approximately $111 million.

2022 Compared to 2021

Midstream segment revenue and segment adjusted EBITDA increased $971 million and $362 million, respectively. Results largely benefited from higher product pricing, mainly due to increased average C2 + NGL prices of $0.16 per gallon. These price increases resulted in higher revenues of approximately $380 million, as well as higher cost of sales of $315 million. The Midstream segment also benefited from higher gathering system throughputs, resulting in increased revenue of $356 million, in addition to higher pipeline and terminal throughputs. Segment adjusted EBITDA increased primarily due to income from equity method investments of approximately $211 million.

Corporate

(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 $100 million, $55 million and $165 million for the years ended December 31, 2023, 2022 and 2021, respectively.

2023 Compared to 2022

Corporate expenses increased $84 million in 2023 compared to 2022 largely due to increases in stock-based compensation expense of $48 million, depreciation and amortization of $45 million, compensation expense of $31 million, contract services expense of $26 million and office expense of $22 million, partially offset by increased allocations of corporate costs to the segments of $75 million.

2022 Compared to 2021

Corporate expenses increased $57 million in 2022 compared to 2021 primarily driven by stock-based and special award compensation expense and retroactive operating tax assessments for prior periods. The company will continue to pursue recovery of these tax assessments. These increases were partially offset by decreased depreciation and amortization of $110 million mainly due to 2021 asset impairments of $56 million and assets that were fully depreciated in 2021.

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.

2023 Compared to 2022

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.

2022 Compared to 2021

In 2022, total items not allocated to segments primarily include the gain of $549 million on the formation of the Martinez Renewables joint venture, the gain of $509 million on a lease reclassification, and a $238 million benefit related to retroactive changes in renewable volume obligation requirements published by EPA for 2020 and 2021.

Non-GAAP Financial Measure

Management uses a financial measure to evaluate our operating performance that is calculated and presented on the basis of methodologies other than in accordance with GAAP. The non-GAAP financial measure we use is 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.

Reconciliation of Refining & Marketing segment adjusted EBITDA to Refining & Marketing gross margin and Refining & Marketing margin

(a) Reflects the gross margin, excluding depreciation and amortization, of other related operations included in the Refining & Marketing segment and processing of credit card transactions on behalf of certain of our marketing customers, net of other income.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance for continuing operations was $5.44 billion at December 31, 2023, compared to $8.63 billion at December 31, 2022. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years is presented in the following table.

Operating Activities

Continuing Operations

Net cash provided by operating activities from continuing operations decreased $2.20 billion in 2023 compared to 2022, primarily due to a decrease in operating results partially offset by a favorable change in working capital of $1.57 billion. Net cash provided by operating activities from continuing operations increased $7.94 billion in 2022 compared to 2021, primarily due to an increase in operating results partially offset by an unfavorable change in working capital of $2.29 billion. The above changes in working capital exclude changes in short-term debt.

For 2023, changes in working capital were a net $230 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.

For 2022, changes in working capital were a net $1.34 billion use of cash, primarily due to the effect of increases in energy commodity prices and volumes at the end of the year on working capital. Current receivables increased primarily due to higher crude oil and refined product volumes and prices. Inventories increased primarily due to increases in crude oil, refined product and materials and supplies inventories. Accounts payable increased primarily due to increases in crude oil prices.

For 2021, changes in working capital were a net $947 million source of cash, primarily due to the effect of increases in energy commodity prices and volumes at the end of the year on working capital. Accounts payable increased primarily due to increases in crude oil prices and volumes. Current receivables increased primarily due to higher crude oil and refined product prices and volumes.

Discontinued Operations

Net cash provided by operating activities from discontinued operations was $42 million in 2022 largely due to the settlement of working capital related to the Speedway sale, partially offset by the payment of state income tax liabilities. Net cash used in operating activities from discontinued operations was $4.02 billion in 2021 primarily due to tax payments related to the sale of Speedway, partially offset by a partial year of business income due to the sale of Speedway on May 14, 2021.

Investing Activities

Continuing Operations

Net cash used in investing activities from continuing operations was $3.10 billion in 2023 and $6.52 billion in 2021, compared to net cash provided by investing activities from continuing operations of $623 million in 2022.

• In 2023, the change in net cash used in continuing operations 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.
• In 2022, the change in net cash provided by continuing operations was primarily due to maturities and sales of short-term investments of $7.16 billion and $1.30 billion, respectively, partially offset by purchases of short-term investments of $6.02 billion. 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.
• In 2021, proceeds from the sale of Speedway were used to purchase $12.50 billion of short-term investments and cash of $5.41 billion and $1.54 billion was provided by the maturities and sales, respectively, of short-term investments. 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 $1.89 billion in 2023, compared to $2.42 billion in 2022 and $1.46 billion in 2021, primarily due to spending in our Refining & Marketing and Midstream segments in 2023. See discussion of capital expenditures and investments under the “Capital Spending” section.
• 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 for acquisitions was $413 million in 2022 primarily due to the purchase of Crowley Coastal Partner’s interest in Crowley Ocean Partners LLC and its four subsidiaries for approximately $485 million, which included $196 million to pay off the debt associated with the four tankers.
• Cash used in net investments was $205 million in 2023 and $171 million in 2021, compared to cash provided by net investments of $110 million in 2022. 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. Investments in 2022 include a $500 million cash distribution received from the Martinez Renewables joint venture at its formation, partially offset by increased contributions to equity method investments, which included the $60 million contribution to MPLX’s Bakken Pipeline joint venture to fund its share of a debt repayment by the joint venture. Investments in 2021 primarily include Midstream projects and our joint venture with ADM.
• Cash provided by disposal of assets totaled $36 million, $90 million and $153 million in 2023, 2022 and 2021, respectively, primarily due to the sale of Midstream assets.

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.

Discontinued Operations

Net cash provided by investing activities from discontinued operations in 2021 primarily includes the $21.38 billion proceeds from the sale of Speedway, partially offset primarily by cash used for Speedway capital expenditures of $177 million.

Financing Activities

Financing activities were a use of cash of $14.21 billion in 2023, $13.65 billion in 2022 and $14.42 billion in 2021.

• 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.
• During 2022, MPLX issued $2.5 billion of senior notes, redeemed $1.0 billion of senior notes and had net payments of $300 million under its revolving credit facility.
• During 2021, we reduced debt through the following actions:
• On December 2, 2021, all of the $1.25 billion outstanding aggregate principal amount of MPC's 4.5 percent senior notes due May 2023 and the $850 million outstanding aggregate principal amount of MPC’s 4.75 percent senior notes due December 2023, including the portion of such notes for which Andeavor LLC was the obligor, were redeemed at a price equal to par, plus a make-whole premium calculated in accordance with the terms of the senior notes and accrued and unpaid interest to, but not including, the redemption date. MPC funded the redemption amount with cash on hand.
• In June 2021, we redeemed all of the $300 million outstanding aggregate principal amount of MPC’s 5.125 percent senior notes due April 2024 at a price equal to 100.854 percent of the principal amount, plus accrued and unpaid interest to, but not including, the redemption date.
• In May 2021, we repaid all outstanding commercial paper borrowings, which, along with cash had been used to finance the fourth quarter 2020 repayments of two series of MPC’s senior notes in the aggregate total principal amount of $1.13 billion.
• On March 1, 2021, we repaid the $1 billion outstanding aggregate principal amount of MPC’s 5.125 percent senior notes due March 2021.
• In 2021, MPLX redeemed $1.75 billion of senior notes and had net borrowings of $300 million under its revolving credit facility.
• Cash used in common stock repurchases totaled $11.57 billion in 2023, $11.92 billion in 2022 and $4.65 billion in 2021. See the “Capital Requirements” section for further discussion of our stock repurchases.
• Cash used in dividend payments totaled $1.26 billion in 2023, $1.28 billion in 2022 and $1.48 billion in 2021. Dividends per share were $3.08 in 2023, $2.49 in 2022 and $2.32 in 2021. The decreases in 2023 and 2022 are primarily due to share repurchases, partially offset by an increase in per share dividends.
• Cash used in distributions to noncontrolling interests totaled $1.28 billion in 2023, $1.21 billion in 2022 and $1.45 billion in 2021 due to distributions to MPLX common and preferred public unitholders. MPLX’s distributions in 2021 included a supplemental distribution amount of $0.5750 per common unit.
• Cash used in repurchases of noncontrolling interests totaled $491 million in 2022 and $630 million in 2021 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 $14.28 billion at December 31, 2023 consisting of:

(a) The committed borrowing and letter of credit issuance capacity of 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 $1.05 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.

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, 2023, 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, 2023, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 20 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 February 1, 2024, the credit ratings on our senior unsecured debt are as follows.

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 20 for further discussion of our debt.

MPLX

MPLX’s liquidity totaled $4.55 billion at December 31, 2023 consisting of:

On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of senior notes in a public offering, consisting of $1.1 billion aggregate principal amount of 5.00 percent senior notes due March 2033 and $500 million aggregate principal amount of 5.65 percent senior notes due March 2053. On February 15, 2023, MPLX used $600 million of the net proceeds to redeem all of the outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds to redeem all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023.

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, 2023, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 20 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 February 1, 2024, the credit ratings on MPLX’s senior unsecured debt are as follows.

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 20 for further discussion of MPLX’s debt.

Capital Requirements

Capital Spending

MPC’s capital investment plan for 2024 totals approximately $1.25 billion for capital projects and investments, excluding capitalized interest, potential acquisitions, if any, and MPLX’s capital investment plan. MPC’s 2024 capital investment plan includes all of the planned capital spending for Refining & Marketing 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 2024 capital investment plan for MPC and MPLX and capital expenditures and investments for each of the last three years are summarized by segment below.

(a) Capital expenditures include changes in capital accruals.

(b) Excludes capitalized interest of $55 million, $103 million and $68 million for 2023, 2022 and 2021, respectively. The 2024 capital investment plan excludes capitalized interest.

(c) The 2024 capital investment plan for Midstream - MPLX excludes $285 million of capital expenditures, which is expected to be incurred primarily by MPC and other MPLX customers on MPLX’s behalf. It also excludes approximately $100 million for repayment of MPLX’s share of the Bakken Pipeline joint venture’s debt due in 2024. This reimbursable capital and the contribution to the joint venture will be included in the 2024 MPC Midstream capital expenditures.

Refining & Marketing

The Refining & Marketing segment’s forecasted 2024 capital spending and investments is approximately $1.20 billion. This amount includes approximately $350 million of growth capital for multi-year low carbon initiatives. At our Los Angeles refinery, we are advancing improvements to enhance the competitiveness of the refinery by improving reliability and lowering costs. The improvements focus on integrating and modernizing utility systems and increasing energy efficiency, with the added benefit of addressing upcoming regulation mandating further reductions in emissions. The improvements are expected to be completed by the end of 2025. There is also $475 million of growth capital which includes a multi-year project to upgrade high sulfur distillate to ULSD and maximize distillate volume expansion at our Galveston Bay refinery, which is expected to be completed by the end of 2027, and other traditional projects that will enhance the yields of our refineries, improve energy efficiency, and lower our costs as well as investments in our branded marketing footprint. Maintenance capital is expected to be approximately $375 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 also focused on projects such as the Martinez facility conversion, the STAR project at our Galveston Bay refinery and projects expected to reduce future operating costs.

Midstream

MPLX’s capital investment plan of $1.10 billion, net of reimbursements, includes approximately $950 million of organic growth capital and $150 million of maintenance capital. This excludes approximately $100 million for the repayment of MPLX’s share of the Bakken Pipeline joint venture’s debt due in 2024. MPLX’s growth capital plans are anchored in the Marcellus, Permian, and Bakken basins. In addition to new gas processing plants in the Marcellus and Permian, the remainder of MPLX’s capital plan is focused on other investments targeted at the expansion or 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.

Corporate and Other

The 2024 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.

Share Repurchases

From January 1, 2012 through December 31, 2023, our board of directors approved $50.05 billion in total share repurchase authorizations and we have repurchased a total of $43.27 billion of our common stock. As of December 31, 2023, MPC had $6.78 billion remaining under its share repurchase authorizations, which reflects the repurchase of 489,190 common shares for $73 million that were transacted in the fourth quarter of 2023 and settled in the first quarter of 2024. The table below summarizes our total share repurchases. See Item 8. Financial Statements and Supplementary Data – Note 10 for further discussion of the share repurchase plans.

(In millions of dollars, except per share data)

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.

(In millions of dollars, except per unit data)

As of December 31, 2023, MPLX had approximately $846 million 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 6 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, 2023, we had purchase obligations for crude oil, NGLs and renewable feedstocks of $17.76 billion, with $14.44 billion payable within 12 months, and crude oil transportation obligations of $7.45 billion, with $835 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, 2023, we have non-cancelable obligations to acquire property, plant and equipment of $281 million, with $276 million payable within 12 months.

At December 31, 2023, we have aggregate principal amount of outstanding senior notes of $27.15 billion, with $1.9 billion payable within 12 months, and interest on the debt of $16.86 billion, with $1.23 billion payable within 12 months. See Item 8. Financial Statements and Supplementary Data – Note 20 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 25, 27 and 23, respectively.

Other Cash Commitments

On January 26, 2024, we announced our board of directors approved a $0.825 per share dividend, payable March 11, 2024 to shareholders of record at the close of business on February 21, 2024.

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 8 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:

(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. Environmental remediation costs increased in 2022 compared to 2021 primarily due to a release of crude oil on an MPLX pipeline near Edwardsville, Illinois in March of 2022.

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 12 percent, 7 percent and 8 percent of capital expenditures, for 2023, 2022 and 2021, respectively, excluding acquisitions. Our environmental capital expenditures are expected to be approximately $272 million, or 12 percent, of total planned capital expenditures in 2024. 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.

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 does 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 18 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. 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

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 is subject to annual, or more frequent if necessary, impairment testing at the reporting unit level. 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, 2023, MPC had four reporting units with goodwill totaling approximately $8.24 billion. The majority of this balance is comprised of the Midstream reporting units, including $1.1 billion for the MPLX Crude Gathering reporting unit and $6.6 billion for the MPLX Transportation & Storage reporting unit. For the annual impairment assessment as of November 30, 2023, management performed only a qualitative assessment for three reporting units as we determined it was more likely than not that the fair value of the reporting units exceeded the carrying value. Significant assumptions used to estimate the reporting units’ fair value under a qualitative approach included estimates of future cash flows and market information for comparable assets. A quantitative assessment was performed for the MPLX Crude Gathering reporting unit, which resulted in the fair value of the reporting unit exceeding its carrying value by greater than 10 percent. The fair value of the reporting unit was determined based on applying both a discounted cash flow method (i.e., income approach) as well as a market approach. An increase of one percentage point to the discount rate used to estimate the fair value of the reporting unit would not have resulted in a goodwill impairment charge as of November 30, 2023. Significant assumptions that were used to estimate the Crude Gathering reporting unit’s fair values under the discounted cash flow method included management’s best estimates of the discount rate, as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact the reporting unit’s future volumes and capital requirements. If estimates for future cash flows were to decline, the overall reporting units’ fair values would decrease, resulting in potential goodwill impairment charges. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the impairment tests will prove to be an accurate prediction of the future.

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, 2023, we had $6.26 billion of investments in equity method investments recorded on our consolidated balance sheet.

See Item 8. Financial Statements and Supplementary Data – Note 15 for additional information on our equity method investments. See Item 8. Financial Statements and Supplementary Data – Note 17 for additional information on our goodwill and intangibles, including a table summarizing our recorded goodwill by segment.

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 18. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

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 (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) 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 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 Item 8. Financial Statements and Supplementary Data – Note 7.

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 4.90 percent for our pension plans and 4.80 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $74 million and $16 million, respectively, and would increase defined benefit pension expense and other postretirement benefit plan expense by $10 million and less than $1 million, respectively.

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 7.00 percent long-term rate of return to determine our 2023 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 6.80 percent effective for 2024. Decreasing the 7.00 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 25 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.

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.

GENERAL

We are exposed to market risks related to the volatility of crude oil and refined product 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, 2023, we did not have any financial derivative instruments to hedge the risks related to interest 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 18 and 19 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 foreign-sourced 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 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.

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.

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, 2023 and 2022, respectively.

See Item 8. Financial Statements and Supplementary Data – Note 19 for additional information on our open derivative positions at December 31, 2023.

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, 2023 is provided in the following table.

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, 2023 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 20 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, 2023 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 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.

(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, 2023.

(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, 2023.

See Item 8. Financial Statements and Supplementary Data – Note 18 for additional information on the fair value of our debt.

Foreign Currency Exchange Rate Risk

We are impacted by foreign exchange rate fluctuations related to some of our purchases of crude oil denominated in Canadian dollars and some of our sales of finished products denominated in Mexican pesos. We did not use derivatives to hedge our market risk exposure to these foreign exchange rate fluctuations in 2023.

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.

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) 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, 2023, the end of the period covered by this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2023, 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.